Contents
Chapter 1—General 1
Part 1.1—Preliminary 1
1.1.......... Name of Determination................................................................................................ 1
Division 1.1.1—Overview 1
1.3.......... Overview—general...................................................................................................... 1
1.4.......... Overview—methods for measurement......................................................................... 2
1.5.......... Overview—energy....................................................................................................... 2
1.6.......... Overview—scope 2 emissions..................................................................................... 2
1.7.......... Overview—assessment of uncertainty......................................................................... 2
Division 1.1.2—Definitions and interpretation 3
1.8.......... Definitions................................................................................................................... 3
1.9.......... Interpretation.............................................................................................................. 18
1.9A....... Meaning of separate instance of a source................................................................. 19
1.9B........ Meaning of separate occurrence of a source............................................................. 19
1.10........ Meaning of source..................................................................................................... 19
Part 1.2—General 22
1.11........ Purpose of Part.......................................................................................................... 22
Division 1.2.1—Measurement and standards 22
1.12........ Measurement of emissions and energy...................................................................... 22
1.13........ General principles for measuring emissions and energy............................................ 22
1.14........ Assessment of uncertainty......................................................................................... 23
1.15........ Units of measurement................................................................................................ 23
1.16........ Rounding of amounts................................................................................................. 23
1.17........ Status of standards..................................................................................................... 23
Division 1.2.2—Methods 24
1.18........ Method to be used for a separate occurrence of a source........................................... 24
1.18A..... Conditions—persons preparing report must use same method.................................. 25
1.19........ Temporary unavailability of method........................................................................... 26
Division 1.2.3—Requirements in relation to carbon capture and storage 27
1.19A..... Meaning of captured for permanent storage............................................................. 27
1.19B...... Deducting greenhouse gas that is captured for permanent storage............................. 27
1.19C...... Capture from facility with multiple sources jointly generated..................................... 28
1.19D..... Capture from a source where multiple fuels consumed.............................................. 28
1.19E...... Measure of quantity of captured greenhouse gas....................................................... 28
1.19F...... Volume of greenhouse gas stream—criterion A........................................................ 29
1.19G..... Volume of greenhouse gas stream—criterion AAA.................................................. 29
1.19GA.. Volume of greenhouse gas stream—criterion BBB................................................... 30
1.19H..... Volumetric measurement—compressed greenhouse gas stream................................ 30
1.19I....... Volumetric measurement—super‑compressed greenhouse gas stream...................... 31
1.19J....... Gas measuring equipment—requirements.................................................................. 32
1.19K...... Flow devices—requirements...................................................................................... 32
1.19L...... Flow computers—requirements................................................................................. 33
1.19M..... Gas chromatographs.................................................................................................. 33
Part 1.3—Method 4—Direct measurement of emissions 34
Division 1.3.1—Preliminary 34
1.20........ Overview................................................................................................................... 34
Division 1.3.2—Operation of method 4 (CEM) 35
Subdivision 1.3.2.1—Method 4 (CEM) 35
1.21........ Method 4 (CEM)—estimation of emissions.............................................................. 35
1.21A..... Emissions from a source where multiple fuels consumed.......................................... 36
Subdivision 1.3.2.2—Method 4 (CEM)—use of equipment 36
1.22........ Overview................................................................................................................... 36
1.23........ Selection of sampling positions for CEM equipment................................................. 36
1.24........ Measurement of flow rates by CEM.......................................................................... 36
1.25........ Measurement of gas concentrations by CEM............................................................. 37
1.26........ Frequency of measurement by CEM.......................................................................... 37
Division 1.3.3—Operation of method 4 (PEM) 38
Subdivision 1.3.3.1—Method 4 (PEM) 38
1.27........ Method 4 (PEM)—estimation of emissions............................................................... 38
1.27A..... Emissions from a source where multiple fuels consumed.......................................... 38
1.28........ Calculation of emission factors.................................................................................. 38
Subdivision 1.3.3.2—Method 4 (PEM)—use of equipment 39
1.29........ Overview................................................................................................................... 39
1.30........ Selection of sampling positions for PEM equipment................................................. 39
1.31........ Measurement of flow rates by PEM equipment......................................................... 39
1.32........ Measurement of gas concentrations by PEM............................................................. 40
1.33........ Representative data for PEM...................................................................................... 40
Division 1.3.4—Performance characteristics of equipment 41
1.34........ Performance characteristics of CEM or PEM equipment........................................... 41
Chapter 2—Fuel combustion 42
Part 2.1—Preliminary 42
2.1.......... Outline of Chapter...................................................................................................... 42
Part 2.2—Emissions released from the combustion of solid fuels 43
Division 2.2.1—Preliminary 43
2.2.......... Application................................................................................................................. 43
2.3.......... Available methods for estimating emissions of carbon dioxide, methane and nitrous oxide 43
Division 2.2.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from solid fuels 44
2.4.......... Method 1—solid fuels............................................................................................... 44
Division 2.2.3—Method 2—emissions from solid fuels 45
Subdivision 2.2.3.1—Method 2—estimating carbon dioxide using default oxidation factor 45
2.5.......... Method 2—estimating carbon dioxide using oxidation factor.................................... 45
Subdivision 2.2.3.2—Method 2—estimating carbon dioxide using an estimated oxidation factor 46
2.6.......... Method 2—estimating carbon dioxide using an estimated oxidation factor................ 46
Subdivision 2.2.3.3—Sampling and analysis for method 2 under sections 2.5 and 2.6 48
2.7.......... General requirements for sampling solid fuels........................................................... 48
2.8.......... General requirements for analysis of solid fuels........................................................ 48
2.9.......... Requirements for analysis of furnace ash and fly ash................................................ 49
2.10........ Requirements for sampling for carbon in furnace ash................................................ 49
2.11........ Sampling for carbon in fly ash................................................................................... 49
Division 2.2.4—Method 3—Solid fuels 51
2.12........ Method 3—solid fuels using oxidation factor or an estimated oxidation factor.......... 51
Division 2.2.5—Measurement of consumption of solid fuels 53
2.13........ Purpose of Division................................................................................................... 53
2.14........ Criteria for measurement............................................................................................ 53
2.15........ Indirect measurement at point of consumption—criterion AA................................... 53
2.16........ Direct measurement at point of consumption—criterion AAA.................................. 56
2.17........ Simplified consumption measurements—criterion BBB............................................ 56
Part 2.3—Emissions released from the combustion of gaseous fuels 57
Division 2.3.1—Preliminary 57
2.18........ Application................................................................................................................. 57
2.19........ Available methods...................................................................................................... 57
Division 2.3.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide 58
2.20........ Method 1—emissions of carbon dioxide, methane and nitrous oxide........................ 58
Division 2.3.3—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels 59
Subdivision 2.3.3.1—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels 59
2.21........ Method 2—emissions of carbon dioxide from the combustion of gaseous fuels....... 59
2.22........ Calculation of emission factors from combustion of gaseous fuel............................. 59
Subdivision 2.3.3.2—Sampling and analysis 61
2.23........ General requirements for sampling under method 2................................................... 61
2.24........ Standards for analysing samples of gaseous fuels..................................................... 62
2.25........ Frequency of analysis................................................................................................ 65
Division 2.3.4—Method 3—emissions of carbon dioxide released from the combustion of gaseous fuels 67
2.26........ Method 3—emissions of carbon dioxide from the combustion of gaseous fuels....... 67
Division 2.3.5—Method 2—emissions of methane from the combustion of gaseous fuels 69
2.27........ Method 2—emissions of methane from the combustion of gaseous fuels................. 69
Division 2.3.6—Measurement of quantity of gaseous fuels 70
2.28........ Purpose of Division................................................................................................... 70
2.29........ Criteria for measurement............................................................................................ 70
2.30........ Indirect measurement—criterion AA......................................................................... 70
2.31........ Direct measurement—criterion AAA......................................................................... 70
2.32........ Volumetric measurement—all natural gases............................................................... 72
2.33........ Volumetric measurement—super‑compressed gases................................................. 73
2.34........ Gas measuring equipment—requirements.................................................................. 73
2.35........ Flow devices—requirements...................................................................................... 73
2.36........ Flow computers—requirements................................................................................. 74
2.37........ Gas chromatographs—requirements.......................................................................... 75
2.38........ Simplified consumption measurements—criterion BBB............................................ 75
Part 2.4—Emissions released from the combustion of liquid fuels 76
Division 2.4.1—Preliminary 76
2.39........ Application................................................................................................................. 76
2.39A..... Definition of petroleum based oils for Part 2.4.......................................................... 76
Subdivision 2.4.1.1—Liquid fuels—other than petroleum based oils and greases 76
2.40........ Available methods...................................................................................................... 76
Subdivision 2.4.1.2—Liquid fuels—petroleum based oils and greases 77
2.40A..... Available methods...................................................................................................... 77
Division 2.4.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from liquid fuels other than petroleum based oils or greases 78
2.41........ Method 1—emissions of carbon dioxide, methane and nitrous oxide........................ 78
Division 2.4.3—Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases 79
Subdivision 2.4.3.1—Method 2—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases 79
2.42........ Method 2—emissions of carbon dioxide from the combustion of liquid fuels........... 79
2.43........ Calculation of emission factors from combustion of liquid fuel................................. 79
Subdivision 2.4.3.2—Sampling and analysis 80
2.44........ General requirements for sampling under method 2................................................... 80
2.45........ Standards for analysing samples of liquid fuels......................................................... 80
2.46........ Frequency of analysis................................................................................................ 83
Division 2.4.4—Method 3—emissions of carbon dioxide from liquid fuels other than petroleum based oils or greases 84
2.47........ Method 3—emissions of carbon dioxide from the combustion of liquid fuels........... 84
Division 2.4.5—Method 2—emissions of methane and nitrous oxide from liquid fuels other than petroleum based oils or greases 87
2.48........ Method 2—emissions of methane and nitrous oxide from the combustion of liquid fuels 87
Division 2.4.5A—Methods for estimating emissions of carbon dioxide from petroleum based oils or greases 88
2.48A..... Method 1—estimating emissions of carbon dioxide using an estimated oxidation factor 88
2.48B...... Method 2—estimating emissions of carbon dioxide using an estimated oxidation factor 89
2.48C...... Method 3—estimating emissions of carbon dioxide using an estimated oxidation factor 89
Division 2.4.6—Measurement of quantity of liquid fuels 90
2.49........ Purpose of Division................................................................................................... 90
2.50........ Criteria for measurement............................................................................................ 90
2.51........ Indirect measurement—criterion AA......................................................................... 90
2.52........ Direct measurement—criterion AAA......................................................................... 90
2.53........ Simplified consumption measurements—criterion BBB............................................ 91
Part 2.5—Emissions released from fuel use by certain industries 92
2.54........ Application................................................................................................................. 92
Division 2.5.1—Energy—petroleum refining 93
2.55........ Application................................................................................................................. 93
2.56........ Methods..................................................................................................................... 93
Division 2.5.2—Energy—manufacture of solid fuels 94
2.57........ Application................................................................................................................. 94
2.58........ Methods..................................................................................................................... 94
Division 2.5.3—Energy—petrochemical production 98
2.59........ Application................................................................................................................. 98
2.60........ Available methods...................................................................................................... 98
2.61........ Method 1—petrochemical production........................................................................ 98
2.62........ Method 2—petrochemical production...................................................................... 100
2.63........ Method 3—petrochemical production...................................................................... 100
Part 2.6—Blended fuels 102
2.64........ Purpose.................................................................................................................... 102
2.65........ Application............................................................................................................... 102
2.66........ Blended solid fuels................................................................................................... 102
2.67........ Blended liquid fuels................................................................................................. 102
2.67A..... Blended gaseous fuels.............................................................................................. 102
Part 2.7—Estimation of energy for certain purposes 104
2.68........ Amount of energy consumed without combustion................................................... 104
2.69........ Apportionment of fuel consumed as carbon reductant or feedstock and energy....... 104
2.70........ Amount of energy consumed in a cogeneration process.......................................... 105
2.71........ Apportionment of energy consumed for electricity, transport and for stationary energy 105
Chapter 3—Fugitive emissions 106
Part 3.1—Preliminary 106
3.1.......... Outline of Chapter.................................................................................................... 106
Part 3.2—Coal mining—fugitive emissions 107
Division 3.2.1—Preliminary 107
3.2.......... Outline of Part.......................................................................................................... 107
Division 3.2.2—Underground mines 108
Subdivision 3.2.2.1—Preliminary 108
3.3.......... Application............................................................................................................... 108
3.4.......... Available methods.................................................................................................... 108
Subdivision 3.2.2.2—Fugitive emissions from extraction of coal 109
3.5.......... Method 1—extraction of coal................................................................................... 109
3.6.......... Method 4—extraction of coal................................................................................... 109
3.7.......... Estimation of emissions........................................................................................... 110
3.8.......... Overview—use of equipment.................................................................................. 111
3.9.......... Selection of sampling positions for PEM................................................................. 111
3.10........ Measurement of volumetric flow rates by PEM....................................................... 111
3.11........ Measurement of concentrations by PEM................................................................. 111
3.12........ Representative data for PEM.................................................................................... 112
3.13........ Performance characteristics of equipment................................................................ 112
Subdivision 3.2.2.3—Emissions released from coal mine waste gas flared 112
3.14........ Method 1—coal mine waste gas flared.................................................................... 112
3.15........ Method 2—emissions of carbon dioxide from coal mine waste gas flared.............. 112
3.15A..... Method 2—emissions of methane and nitrous oxide from coal mine waste gas flared 113
3.16........ Method 3—coal mine waste gas flared.................................................................... 113
Subdivision 3.2.2.4—Fugitive emissions from post‑mining activities 114
3.17........ Method 1—post‑mining activities related to gassy mines........................................ 114
Division 3.2.3—Open cut mines 115
Subdivision 3.2.3.1—Preliminary 115
3.18........ Application............................................................................................................... 115
3.19........ Available methods.................................................................................................... 115
Subdivision 3.2.3.2—Fugitive emissions from extraction of coal 116
3.20........ Method 1—extraction of coal................................................................................... 116
3.21........ Method 2—extraction of coal................................................................................... 116
3.22........ Total gas contained by gas bearing strata................................................................. 117
3.23........ Estimate of proportion of gas content released below pit floor................................. 118
3.24........ General requirements for sampling.......................................................................... 119
3.25........ General requirements for analysis of gas and gas bearing strata.............................. 119
3.25A..... Method of working out base of the low gas zone.................................................... 119
3.25B...... Further requirements for estimator........................................................................... 120
3.25C...... Default gas content for gas bearing strata in low gas zone....................................... 121
3.25D..... Requirements for estimating total gas contained in gas bearing strata...................... 121
3.26........ Method 3—extraction of coal................................................................................... 121
Subdivision 3.2.3.3—Emissions released from coal mine waste gas flared 122
3.27........ Method 1—coal mine waste gas flared.................................................................... 122
3.28........ Method 2—coal mine waste gas flared.................................................................... 122
3.29........ Method 3—coal mine waste gas flared.................................................................... 122
Division 3.2.4—Decommissioned underground mines 123
Subdivision 3.2.4.1—Preliminary 123
3.30........ Application............................................................................................................... 123
3.31........ Available methods.................................................................................................... 123
Subdivision 3.2.4.2—Fugitive emissions from decommissioned underground mines 124
3.32........ Method 1—decommissioned underground mines.................................................... 124
3.33........ Emission factor for decommissioned underground mines........................................ 124
3.34........ Measurement of proportion of mine that is flooded................................................. 125
3.35........ Water flow into mine................................................................................................ 125
3.36........ Size of mine void volume......................................................................................... 125
3.37........ Method 4—decommissioned underground mines.................................................... 126
Subdivision 3.2.4.3—Fugitive emissions from coal mine waste gas flared 126
3.38........ Method 1—coal mine waste gas flared.................................................................... 126
3.39........ Method 2—coal mine waste gas flared.................................................................... 126
3.40........ Method 3—coal mine waste gas flared.................................................................... 126
Part 3.3—Oil and natural gas—fugitive emissions 127
Division 3.3.1—Preliminary 127
3.41........ Outline of Part.......................................................................................................... 127
3.41A..... Interpretation............................................................................................................ 128
Division 3.3.2—Oil or gas exploration and development 129
Subdivision 3.3.2.1—Preliminary 129
3.42........ Application............................................................................................................... 129
Subdivision 3.3.2.2—Oil or gas exploration and development (emissions that are flared) 129
3.43........ Available methods.................................................................................................... 129
3.44........ Method 1—oil or gas exploration and development................................................. 130
3.45........ Method 2—oil or gas exploration and development (flared carbon dioxide emissions) 130
3.45A..... Method 2A—oil or gas exploration and development (flared methane or nitrous oxide emissions) 131
3.46........ Method 3—oil or gas exploration and development................................................. 131
Subdivision 3.3.2.3—Oil or gas exploration and development—fugitive emissions from system upsets, accidents and deliberate releases 132
3.46A..... Available methods.................................................................................................... 132
Subdivision 3.3.2.3.1—Fugitive emissions that result from deliberate releases from process vents, system upsets and accidents–well completions 132
3.46AB... Method 1—vented emissions from natural gas well completions............................ 132
3.46B...... Method 4—vented emissions from natural gas well completions, well workovers, cold process vents and well blowouts................................................................................................................................. 134
Division 3.3.3—Crude oil production 135
Subdivision 3.3.3.1—Preliminary 135
3.47........ Application............................................................................................................... 135
Subdivision 3.3.3.2—Crude oil production (non‑flared)—fugitive leak emissions of methane 135
3.48........ Available methods.................................................................................................... 135
3.49........ Method 1—crude oil production (non‑flared) emissions of methane....................... 136
3.50........ Method 2—crude oil production (non‑flared) emissions of methane....................... 136
Subdivision 3.3.3.3—Crude oil production (flared)—fugitive emissions of carbon dioxide, methane and nitrous oxide 139
3.52........ Available methods.................................................................................................... 139
3.53........ Method 1—crude oil production (flared) emissions................................................. 139
3.54........ Method 2—crude oil production.............................................................................. 140
3.54A..... Method 2A—crude oil production (flared methane or nitrous oxide emissions)...... 140
3.55........ Method 3—crude oil production.............................................................................. 141
Subdivision 3.3.3.4—Crude oil production (non‑flared)—fugitive vent emissions of methane and carbon dioxide 141
3.56A..... Available methods.................................................................................................... 141
3.56B...... Method 1—emissions from system upsets, accidents and deliberate releases from process vents 142
Division 3.3.4—Crude oil transport 143
3.57........ Application............................................................................................................... 143
3.58........ Available methods.................................................................................................... 143
3.59........ Method 1—crude oil transport................................................................................. 143
3.60........ Method 2—fugitive emissions from crude oil transport........................................... 143
Division 3.3.5—Crude oil refining 145
3.62........ Application............................................................................................................... 145
3.63........ Available methods.................................................................................................... 145
Subdivision 3.3.5.1—Fugitive emissions from crude oil refining and from storage tanks for crude oil 146
3.64........ Method 1—crude oil refining and storage tanks for crude oil.................................. 146
3.65........ Method 2—crude oil refining and storage tanks for crude oil.................................. 146
Subdivision 3.3.5.2—Fugitive emissions from deliberate releases from process vents, system upsets and accidents 148
3.67........ Method 1—fugitive emissions from deliberate releases from process vents, system upsets and accidents 148
3.68........ Method 4—deliberate releases from process vents, system upsets and accidents.... 148
Subdivision 3.3.5.3—Fugitive emissions released from gas flared from the oil refinery 148
3.69........ Method 1—gas flared from crude oil refining.......................................................... 148
3.70........ Method 2—gas flared from crude oil refining.......................................................... 149
3.70A..... Method 2A—crude oil refining (flared methane or nitrous oxide emissions).......... 149
3.71........ Method 3—gas flared from crude oil refining.......................................................... 150
Division 3.3.6A—Onshore natural gas production (other than emissions that are vented or flared) 151
3.72........ Application............................................................................................................... 151
Subdivision 3.3.6A.1—Onshore natural gas production, other than emissions that are vented or flared—wellheads 151
3.73........ Available methods.................................................................................................... 151
3.73B...... Method 2—onshore natural gas production, other than emissions that are vented or flared—wellheads 152
Division 3.3.6B—Offshore natural gas production (other than emissions that are vented or flared) 157
3.73D..... Application............................................................................................................... 157
Subdivision 3.3.6B.1—Offshore natural gas production, other than emissions that are vented or flared—offshore platforms 157
3.73E...... Available methods.................................................................................................... 157
3.73F...... Method 1—offshore natural gas production (other than emissions that are vented or flared) 157
3.73G..... Method 2—offshore natural gas production (other than venting and flaring).......... 158
Division 3.3.6C—Natural gas gathering and boosting (other than emissions that are vented or flared) 163
3.73I....... Application............................................................................................................... 163
3.73J....... Available methods.................................................................................................... 163
3.73K...... Method 1—natural gas gathering and boosting (other than venting and flaring)...... 163
3.73L...... Method 2—natural gas gathering and boosting (other than venting and flaring)...... 166
3.73LA... Method 2—natural gas gathering and boosting, other than emissions that are vented or flared—natural gas gathering and boosting stations................................................................................................ 166
Division 3.3.6D—Produced water from oil and gas exploration and development, crude oil production, natural gas production or natural gas gathering and boosting (other than emissions that are vented or flared) 173
3.73N..... Available methods.................................................................................................... 173
3.73NA.. Method 1—produced water (other than emissions that are vented or flared)........... 173
3.73NB... Method 2—produced water (other than emissions that are vented or flared)........... 174
Division 3.3.6E—Natural gas processing (other than emissions that are vented or flared) 176
3.73O..... Application............................................................................................................... 176
3.73P...... Available methods.................................................................................................... 176
3.73Q..... Method 1—natural gas processing (other than emissions that are vented or flared). 176
3.73R...... Method 2—natural gas processing (other than venting and flaring)......................... 178
3.73S...... Method 3—natural gas processing (other than venting and flaring)......................... 179
Division 3.3.7—Natural gas transmission (other than emissions that are flared) 182
3.74........ Application............................................................................................................... 182
3.75........ Available methods.................................................................................................... 182
3.76........ Method 1—natural gas transmission (other than flaring)......................................... 182
3.77........ Method 2—natural gas transmission (other than flaring)......................................... 182
Division 3.3.7A—Natural gas storage (other than emissions that are vented or flared) 185
3.78A..... Application............................................................................................................... 185
3.78B...... Available methods.................................................................................................... 185
3.78C...... Method 1—natural gas storage (other than emissions that are vented or flared)...... 185
3.78D..... Method 2—natural gas storage (other than emissions that are vented or flared)...... 186
3.78E...... Method 3—natural gas storage (other than emissions that are vented or flared)...... 187
Division 3.3.7B—Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared) 190
3.78F...... Application............................................................................................................... 190
3.78G..... Available methods.................................................................................................... 190
3.78H..... Method 1—natural gas liquefaction, storage and transfer (other than emissions that are vented or flared) 190
3.78I....... Method 2—natural gas liquefaction, storage and transfer (other than emissions that are vented or flared) 191
3.78J....... Method 3—natural gas liquefaction, storage and transfer (other than venting and flaring) 192
Division 3.3.8—Natural gas distribution (other than emissions that are flared) 195
3.79........ Application............................................................................................................... 195
3.80........ Available methods.................................................................................................... 195
3.81........ Method 1—natural gas distribution.......................................................................... 195
3.82........ Method 2—natural gas distribution.......................................................................... 196
3.82A..... Method 3—natural gas distribution.......................................................................... 197
Division 3.3.9A—Natural gas production (emissions that are vented or flared) 199
3.83........ Application............................................................................................................... 199
Subdivision 3.3.9A.1—Natural gas production—emissions that are vented—gas treatment processes 199
3.84........ Available methods.................................................................................................... 199
3.85........ Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas treatment processes.................................................................................................................. 199
Subdivision 3.3.9A.2—Natural gas production—emissions that are vented—cold process vents 200
3.85A..... Available methods.................................................................................................... 200
3.85B...... Method 1—emissions from system upsets, accidents and deliberate releases from process vents 200
Subdivision 3.3.9A.3—Natural gas production—emissions that are vented—natural gas blanketed tanks and condensate storage tanks 200
3.85C...... Available methods.................................................................................................... 200
3.85D..... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—natural gas blanketed tanks and condensate storage tanks.......................................................................... 201
Subdivision 3.3.9A.4—Natural gas production—emissions that are vented—gas driven pneumatic devices 201
3.85E...... Available methods.................................................................................................... 201
3.85F...... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas driven pneumatic devices..................................................................................................................... 201
Subdivision 3.3.9A.5—Natural gas production—emissions that are vented—gas driven chemical injection pumps 202
3.85G..... Available methods.................................................................................................... 202
3.85H..... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas driven chemical injection pumps........................................................................................................ 202
Subdivision 3.3.9A.6—Natural gas production—emissions that are vented—well blowouts 202
3.85K...... Available methods.................................................................................................... 202
3.85L...... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—well blowouts.................................................................... 203
Subdivision 3.3.9A.7—Natural gas production—emissions that are vented—CO2 stimulation 203
3.85M..... Available methods.................................................................................................... 203
3.85N..... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—CO2 stimulation................................................................. 203
Subdivision 3.3.9A.8—Natural gas production—emissions that are vented—well workovers 204
3.85O..... Available methods.................................................................................................... 204
3.85P...... Method 1—vented emissions from well workovers................................................ 204
3.85Q..... Method 4—vented emissions from gas well workovers.......................................... 205
Subdivision 3.3.9A.9—Natural gas production—emissions that are vented—vessel blowdowns, compressor starts and compressor blowdowns 205
3.85R...... Available methods.................................................................................................... 205
3.85S...... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—production related non-routine emissions—vessel blowdowns, compressor starts and compressor blowdowns 206
Subdivision 3.3.9A.10—Natural gas production (emissions that are flared) 206
3.86........ Method 1—gas flared from natural gas production.................................................. 207
3.87........ Method 2—gas flared from natural gas production.................................................. 207
3.87A..... Method 2A—natural gas production (flared methane or nitrous oxide emissions).. 208
3.88........ Method 3—gas flared from natural gas production.................................................. 208
Division 3.3.9B—Natural gas gathering and boosting (emissions that are vented or flared) 209
3.88A..... Application............................................................................................................... 209
Subdivision 3.3.9B.1—Natural gas gathering and boosting (emissions that are vented) 209
3.88B...... Available methods.................................................................................................... 209
3.88C...... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas gathering and boosting emissions................................................................................................... 209
Subdivision 3.3.9B.2—Natural gas gathering and boosting (emissions that are flared) 210
Division 3.3.9C—Natural gas processing (emissions that are vented or flared) 211
3.88E...... Application............................................................................................................... 211
Subdivision 3.3.9C.1—Natural gas processing (emissions that are vented) 211
3.88F...... Available methods.................................................................................................... 211
3.88G..... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas processing................................................................................................................................. 211
Subdivision 3.3.9C.2—Natural gas processing (emissions that are flared) 211
Division 3.3.9D—Natural gas transmission (emissions that are flared) 213
3.88I....... Application............................................................................................................... 213
Division 3.3.9E—Natural gas storage (emissions that are vented or flared) 214
3.88K...... Application............................................................................................................... 214
Subdivision 3.3.9E.1——Natural gas storage (emissions that are vented) 214
3.88L...... Available methods.................................................................................................... 214
3.88M..... Method 1—emissions from system upsets, accidents and deliberate releases from process vents—gas storage related non‑routine emissions.............................................................................................. 214
Subdivision 3.3.9E.2—Natural gas storage (emissions that are flared) 215
Division 3.3.9F— Natural gas liquefaction, storage and transfer (emissions that are vented or flared) 216
3.88O..... Application............................................................................................................... 216
Subdivision 3.3.9F.1—Natural gas liquefaction, storage and transfer (emissions that are vented) 216
3.88P...... Available methods.................................................................................................... 216
3.88Q..... Method 1—emissions from system upsets, accidents and deliberate releases from process vents— natural gas liquefaction, storage and transfer.............................................................................. 216
Subdivision 3.3.9F.2—Natural gas liquefaction, storage and transfer (emissions that are flared) 217
Division 3.3.9G—Natural gas distribution (emissions that are flared) 218
3.88S...... Application............................................................................................................... 218
Part 3.4—Carbon capture and storage and enhanced oil recovery—fugitive emissions 219
Division 3.4.1—Preliminary 219
3.88U..... Outline of Part.......................................................................................................... 219
Division 3.4.2—Transport of greenhouse gases 220
Subdivision 3.4.2.1—Preliminary 220
3.89........ Application............................................................................................................... 220
3.90........ Available methods.................................................................................................... 220
Subdivision 3.4.2.2—Emissions from transport of greenhouse gases involving transfer 221
3.91........ Method 1—emissions from transport of greenhouse gases involving transfer........ 221
Subdivision 3.4.2.3—Emissions from transport of greenhouse gases not involving transfer 221
3.92........ Method 1—emissions from transport of greenhouse gases not involving transfer.. 221
Division 3.4.3—Injection of greenhouse gases 223
Subdivision 3.4.3.1—Preliminary 223
3.93........ Application............................................................................................................... 223
3.94........ Available methods.................................................................................................... 223
Subdivision 3.4.3.2—Fugitive emissions from deliberate releases from process vents, system upsets and accidents 224
3.95........ Method 2—fugitive emissions from deliberate releases from process vents, system upsets and accidents 224
Subdivision 3.4.3.3—Fugitive emissions from injection of greenhouse gases (other than emissions from deliberate releases from process vents, system upsets and accidents) 224
3.96........ Method 2—fugitive emissions from injection of a greenhouse gas into a geological formation (other than deliberate releases from process vents, system upsets and accidents)...................................... 224
3.97........ Method 3—fugitive emissions from injection of greenhouse gases (other than deliberate releases from process vents, system upsets and accidents).................................................................................... 225
Division 3.4.4—Storage of greenhouse gases 226
Subdivision 3.4.4.1—Preliminary 226
3.98........ Application............................................................................................................... 226
3.99........ Available method..................................................................................................... 226
Subdivision 3.4.4.2—Fugitive emissions from the storage of greenhouse gases 226
3.100...... Method 2—fugitive emissions from geological formations used for the storage of greenhouse gases 226
Chapter 4—Industrial processes emissions 228
Part 4.1—Preliminary 228
4.1.......... Outline of Chapter.................................................................................................... 228
Part 4.2—Industrial processes—mineral products 229
Division 4.2.1—Cement clinker production 229
4.2.......... Application............................................................................................................... 229
4.3.......... Available methods.................................................................................................... 229
4.4.......... Method 1—cement clinker production..................................................................... 229
4.5.......... Method 2—cement clinker production..................................................................... 230
4.6.......... General requirements for sampling cement clinker................................................... 231
4.7.......... General requirements for analysing cement clinker.................................................. 231
4.8.......... Method 3—cement clinker production..................................................................... 231
4.9.......... General requirements for sampling carbonates......................................................... 233
4.10........ General requirements for analysing carbonates........................................................ 233
Division 4.2.2—Lime production 234
4.11........ Application............................................................................................................... 234
4.12........ Available methods.................................................................................................... 234
4.13........ Method 1—lime production..................................................................................... 234
4.14........ Method 2—lime production..................................................................................... 235
4.15........ General requirements for sampling.......................................................................... 236
4.16........ General requirements for analysis of lime................................................................ 236
4.17........ Method 3—lime production..................................................................................... 236
4.18........ General requirements for sampling.......................................................................... 237
4.19........ General requirements for analysis of carbonates...................................................... 238
Division 4.2.3—Use of carbonates for production of a product other than cement clinker, lime or soda ash 239
4.20........ Application............................................................................................................... 239
4.21........ Available methods.................................................................................................... 239
4.22........ Method 1—product other than cement clinker, lime or soda ash.............................. 240
4.22A..... Method 1A—product other than cement clinker, lime or soda ash for use of carbonates in clay materials 240
4.23........ Method 3—product other than cement clinker, lime or soda ash.............................. 241
4.23A..... Method 3A—product other than cement clinker, lime or soda ash for use of carbonates in clay materials 242
4.23B...... General requirements for sampling clay material...................................................... 243
4.23C...... General requirements for analysing clay material..................................................... 243
4.24........ General requirements for sampling carbonates......................................................... 243
4.25........ General requirements for analysis of carbonates...................................................... 244
Division 4.2.4—Soda ash use and production 245
4.26........ Application............................................................................................................... 245
4.27........ Outline of Division.................................................................................................. 245
Subdivision 4.2.4.1—Soda ash use 245
4.28........ Available methods.................................................................................................... 245
4.29........ Method 1—use of soda ash..................................................................................... 245
Subdivision 4.2.4.2—Soda ash production 246
4.30........ Available methods.................................................................................................... 246
4.31........ Method 1—production of soda ash.......................................................................... 246
4.32........ Method 2—production of soda ash.......................................................................... 248
4.33........ Method 3—production of soda ash.......................................................................... 250
Division 4.2.5—Measurement of quantity of carbonates consumed and products derived from carbonates 251
4.34........ Purpose of Division................................................................................................. 251
4.35........ Criteria for measurement.......................................................................................... 251
4.36........ Indirect measurement at point of consumption or production—criterion AA........... 252
4.37........ Direct measurement at point of consumption or production—criterion AAA.......... 252
4.38........ Acquisition or use or disposal without commercial transaction—criterion BBB...... 253
4.39........ Units of measurement.............................................................................................. 253
Part 4.3—Industrial processes—chemical industry 254
Division 4.3.1—Ammonia production 254
4.40........ Application............................................................................................................... 254
4.41........ Available methods.................................................................................................... 254
4.42........ Method 1—ammonia production............................................................................. 254
4.43........ Method 2—ammonia production............................................................................. 255
4.44........ Method 3—ammonia production............................................................................. 256
Division 4.3.2—Nitric acid production 257
4.45........ Application............................................................................................................... 257
4.46........ Available methods.................................................................................................... 257
4.47........ Method 1—nitric acid production............................................................................ 257
4.48........ Method 2—nitric acid production............................................................................ 258
Division 4.3.3—Adipic acid production 259
4.49........ Application............................................................................................................... 259
4.50........ Available methods.................................................................................................... 259
Division 4.3.4—Carbide production 260
4.51........ Application............................................................................................................... 260
4.52........ Available methods.................................................................................................... 260
Division 4.3.5—Chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode 261
4.53........ Application............................................................................................................... 261
4.54........ Available methods.................................................................................................... 261
4.55........ Method 1—chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode................................................................................................................................. 261
4.56........ Method 2—chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode................................................................................................................................. 263
4.57........ Method 3—chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode................................................................................................................................. 264
Division 4.3.6—Sodium cyanide production 265
4.58........ Application............................................................................................................... 265
4.59........ Available methods.................................................................................................... 265
Division 4.3.7—Hydrogen production 265
4.60........ Application............................................................................................................... 265
4.61........ Available methods.................................................................................................... 265
4.62A..... Method 2—hydrogen production............................................................................. 267
4.62B...... Method 3—hydrogen production............................................................................. 268
Part 4.4—Industrial processes—metal industry 269
Division 4.4.1—Iron, steel or other metal production using an integrated metalworks 269
4.63........ Application............................................................................................................... 269
4.64........ Purpose of Division................................................................................................. 269
4.65........ Available methods for production of a metal from an integrated metalworks........... 269
4.66........ Method 1—production of a metal from an integrated metalworks........................... 270
4.67........ Method 2—production of a metal from an integrated metalworks........................... 271
4.68........ Method 3—production of a metal from an integrated metalworks........................... 272
Division 4.4.2—Ferroalloys production 273
4.69........ Application............................................................................................................... 273
4.70........ Available methods.................................................................................................... 273
4.71........ Method 1—ferroalloy metal..................................................................................... 273
4.72........ Method 2—ferroalloy metal..................................................................................... 275
4.73........ Method 3—ferroalloy metal..................................................................................... 276
Division 4.4.3—Aluminium production (carbon dioxide emissions) 277
4.74........ Application............................................................................................................... 277
Sudivision 4.4.3.1—Aluminium—emissions from consumption of carbon anodes in aluminium production 277
4.75........ Available methods.................................................................................................... 277
4.76........ Method 1—aluminium (carbon anode consumption)............................................... 277
4.77........ Method 2—aluminium (carbon anode consumption)............................................... 278
4.78........ Method 3—aluminium (carbon anode consumption)............................................... 278
Subdivision 4.4.3.2—Aluminium—emissions from production of baked carbon anodes in aluminium production 278
4.79........ Available methods.................................................................................................... 278
4.80........ Method 1—aluminium (baked carbon anode production)........................................ 279
4.81........ Method 2—aluminium (baked carbon anode production)........................................ 279
4.82........ Method 3—aluminium (baked carbon anode production)........................................ 280
Division 4.4.4—Aluminium production (perfluoronated carbon compound emissions) 281
4.83........ Application............................................................................................................... 281
Subdivision 4.4.4.1—Aluminium—emissions of tetrafluoromethane in aluminium production 281
4.84........ Available methods.................................................................................................... 281
4.86........ Method 2—aluminium (tetrafluoromethane)............................................................ 281
4.87........ Method 3—aluminium (tetrafluoromethane)............................................................ 281
Subdivision 4.4.4.2—Aluminium—emissions of hexafluoroethane in aluminium production 281
4.88........ Available methods.................................................................................................... 281
4.90........ Method 2—aluminium production (hexafluoroethane)............................................ 282
4.91........ Method 3—aluminium production (hexafluoroethane)............................................ 282
Division 4.4.5—Other metals production 283
4.92........ Application............................................................................................................... 283
4.93........ Available methods.................................................................................................... 283
4.94........ Method 1—other metals........................................................................................... 283
4.95........ Method 2—other metals........................................................................................... 285
4.96........ Method 3—other metals........................................................................................... 286
Part 4.5—Industrial processes—emissions of hydrofluorocarbons and sulphur hexafluoride gases 287
4.97........ Application............................................................................................................... 287
4.98........ Available method..................................................................................................... 287
4.99........ Meaning of hydrofluorocarbons.............................................................................. 287
4.100...... Meaning of synthetic gas generating activities......................................................... 287
4.101...... Reporting threshold.................................................................................................. 288
4.102...... Method 1.................................................................................................................. 288
4.103...... Method 2.................................................................................................................. 289
4.104...... Method 3.................................................................................................................. 290
Chapter 5—Waste 291
Part 5.1—Preliminary 291
5.1.......... Outline of Chapter.................................................................................................... 291
Part 5.2—Solid waste disposal on land 292
Division 5.2.1—Preliminary 292
5.2.......... Application............................................................................................................... 292
5.3.......... Available methods.................................................................................................... 292
Division 5.2.2—Method 1—emissions of methane released from landfills 294
5.4.......... Method 1—methane released from landfills (other than from flaring of methane)... 294
5.4A....... Estimates for calculating CH4gen............................................................................... 295
5.4B........ Equation—change in quantity of particular opening stock at landfill for calculating CH4gen 296
5.4C........ Equation—quantity of closing stock at landfill in particular reporting year.............. 297
5.4D....... Equation—quantity of methane generated by landfill for calculating CH4gen............ 297
5.5.......... Criteria for estimating tonnage of total solid waste................................................... 299
5.6.......... Criterion A............................................................................................................... 299
5.7.......... Criterion AAA......................................................................................................... 299
5.8.......... Criterion BBB.......................................................................................................... 300
5.9.......... Composition of solid waste...................................................................................... 300
5.10........ General waste streams.............................................................................................. 300
5.10A..... Homogenous waste streams..................................................................................... 302
5.11........ Waste mix types....................................................................................................... 303
5.11A..... Certain waste to be deducted from waste received at landfill when estimating waste disposed in landfill 306
5.12........ Degradable organic carbon content.......................................................................... 306
5.13........ Opening stock of degradable organic carbon for the first reporting period.............. 307
5.14........ Methane generation constants—(k values)............................................................... 308
5.14A..... Fraction of degradable organic carbon dissimilated (DOCF).................................... 311
5.14B...... Methane correction factor (MCF) for aerobic decomposition.................................. 312
5.14C...... Fraction by volume generated in landfill gas that is methane (F).............................. 312
5.14D..... Number of months before methane generation at landfill commences...................... 312
Division 5.2.3—Method 2—emissions of methane released from landfills 313
Subdivision 5.2.3.1—methane released from landfills 313
5.15........ Method 2—methane released by landfill (other than from flaring of methane)........ 313
5.15A..... Equation—change in quantity of particular opening stock at landfill for calculating CH4gen 316
5.15B...... Equation—quantity of closing stock at landfill in particular reporting year.............. 317
5.15C...... Equation—collection efficiency limit at landfill in particular reporting year............. 317
Subdivision 5.2.3.2—Requirements for calculating the methane generation constant (k) 318
5.16........ Procedures for selecting representative zone............................................................ 318
5.17........ Site plan—preparation and requirements.................................................................. 318
5.17AA.. Sub‑facility zones—maximum number and requirements........................................ 319
5.17A..... Representative zones—selection and requirements.................................................. 319
5.17B...... Independent verification........................................................................................... 320
5.17C...... Estimation of waste and degradable organic content in representative zone............. 320
5.17D..... Estimation of gas collected at the representative zone............................................... 320
5.17E...... Estimating methane generated but not collected in the representative zone............... 321
5.17F...... Walkover survey...................................................................................................... 321
5.17G..... Installation of flux boxes in representative zone....................................................... 322
5.17H..... Flux box measurements........................................................................................... 324
5.17I....... When flux box measurements must be taken........................................................... 325
5.17J....... Restrictions on taking flux box measurements......................................................... 325
5.17K...... Frequency of measurement...................................................................................... 326
5.17L...... Calculating the methane generation constant (ki) for certain waste mix types........... 326
Division 5.2.4—Method 3—emissions of methane released from solid waste at landfills 328
5.18........ Method 3—methane released from solid waste at landfills (other than from flaring of methane) 328
Division 5.2.5—Solid waste at landfills—Flaring 329
5.19........ Method 1—landfill gas flared.................................................................................. 329
5.20........ Method 2—landfill gas flared.................................................................................. 329
5.21........ Method 3—landfill gas flared.................................................................................. 329
Division 5.2.6—Biological treatment of solid waste 330
5.22........ Method 1—emissions of methane and nitrous oxide from biological treatment of solid waste 330
5.22AA.. Method 4—emissions of methane and nitrous oxide from biological treatment of solid waste 330
Division 5.2.7—Legacy emissions and non‑legacy emissions 331
5.22A..... Legacy emissions estimated using method 1—sub‑facility zone options................. 331
5.22B...... Legacy emissions—formula and unit of measurement............................................. 331
5.22C...... How to estimate quantity of methane captured for combustion from legacy waste for each sub‑facility zone 332
5.22D..... How to estimate quantity of methane in landfill gas flared from legacy waste in a sub‑facility zone 333
5.22E...... How to estimate quantity of methane captured for transfer out of landfill from legacy waste for each sub‑facility zone................................................................................................................................. 333
5.22F...... How to calculate the quantity of methane generated from legacy waste for a sub‑facility zone (CH4genlw z) 334
5.22G..... How to calculate total methane generated from legacy waste................................... 334
5.22H..... How to calculate total methane captured and combusted from methane generated from legacy waste 334
5.22J....... How to calculate total methane captured and transferred offsite from methane generated from legacy waste 335
5.22K...... How to calculate total methane flared from methane generated from legacy waste... 335
5.22L...... How to calculate methane generated in landfill gas from non‑legacy waste............. 335
5.22M..... Calculating amount of total waste deposited at landfill............................................. 336
Part 5.3—Wastewater handling (domestic and commercial) 337
Division 5.3.1—Preliminary 337
5.23........ Application............................................................................................................... 337
5.24........ Available methods.................................................................................................... 337
Division 5.3.2—Method 1—methane released from wastewater handling (domestic and commercial) 339
5.25........ Method 1—methane released from wastewater handling (domestic and commercial) 339
Division 5.3.3—Method 2—methane released from wastewater handling (domestic and commercial) 343
5.26........ Method 2—methane released from wastewater handling (domestic and commercial) 343
5.26A..... Requirements relating to sub‑facilities...................................................................... 347
5.27........ General requirements for sampling under method 2................................................. 347
5.28........ Standards for analysis.............................................................................................. 348
5.29........ Frequency of sampling and analysis........................................................................ 348
Division 5.3.4—Method 3—methane released from wastewater handling (domestic and commercial) 349
5.30........ Method 3—methane released from wastewater handling (domestic and commercial) 349
Division 5.3.5—Method 1—emissions of nitrous oxide released from wastewater handling (domestic and commercial) 350
5.31........ Method 1—nitrous oxide released from wastewater handling (domestic and commercial) 350
Division 5.3.6—Method 2—emissions of nitrous oxide released from wastewater handling (domestic and commercial) 353
5.32........ Method 2—nitrous oxide released from wastewater handling (domestic and commercial) 353
5.33........ General requirements for sampling under method 2................................................. 353
5.34........ Standards for analysis.............................................................................................. 354
5.35........ Frequency of sampling and analysis........................................................................ 354
Division 5.3.7—Method 3—emissions of nitrous oxide released from wastewater handling (domestic and commercial) 355
5.36........ Method 3—nitrous oxide released from wastewater handling (domestic and commercial) 355
Division 5.3.8—Wastewater handling (domestic and commercial)—Flaring 356
5.37........ Method 1—Flaring of methane in sludge biogas from wastewater handling (domestic and commercial) 356
5.38........ Method 2—flaring of methane in sludge biogas...................................................... 356
5.39........ Method 3—flaring of methane in sludge biogas...................................................... 356
Part 5.4—Wastewater handling (industrial) 357
Division 5.4.1—Preliminary 357
5.40........ Application............................................................................................................... 357
5.41........ Available methods.................................................................................................... 357
Division 5.4.2—Method 1—methane released from wastewater handling (industrial) 358
5.42........ Method 1—methane released from wastewater handling (industrial)....................... 358
Division 5.4.3—Method 2—methane released from wastewater handling (industrial) 362
5.43........ Method 2—methane released from wastewater handling (industrial)....................... 362
5.44........ General requirements for sampling under method 2................................................. 362
5.45........ Standards for analysis.............................................................................................. 362
5.46........ Frequency of sampling and analysis........................................................................ 363
Division 5.4.4—Method 3—methane released from wastewater handling (industrial) 364
5.47........ Method 3—methane released from wastewater handling (industrial)....................... 364
Division 5.4.5—Wastewater handling (industrial)—Flaring of methane in sludge biogas 365
5.48........ Method 1—flaring of methane in sludge biogas...................................................... 365
5.49........ Method 2—flaring of methane in sludge biogas...................................................... 365
5.50........ Method 3—flaring of methane in sludge biogas...................................................... 365
Part 5.5—Waste incineration 366
5.51........ Application............................................................................................................... 366
5.52........ Available methods—emissions of carbon dioxide from waste incineration............. 366
5.53........ Method 1—emissions of carbon dioxide released from waste incineration.............. 366
Chapter 6—Energy 368
Part 6.1—Production 368
6.1.......... Purpose.................................................................................................................... 368
6.2.......... Quantity of energy produced.................................................................................... 368
6.3.......... Energy content of fuel produced.............................................................................. 369
Part 6.2—Consumption 371
6.4.......... Purpose.................................................................................................................... 371
6.5.......... Energy content of energy consumed........................................................................ 371
Chapter 7—Scope 2 emissions 374
7.1.......... Application............................................................................................................... 374
7.2.......... Method A1—location-based method—electricity purchased, acquired or lost from main electricity grid in a State or Territory................................................................................................................... 374
7.3.......... Method A2—location-based method—electricity purchased, acquired or lost from other sources 375
7.4.......... Method B—market-based method........................................................................... 376
Chapter 8—Assessment of uncertainty 378
Part 8.1—Preliminary 378
8.1.......... Outline of Chapter.................................................................................................... 378
Part 8.2—General rules for assessing uncertainty 379
8.2.......... Range for emission estimates................................................................................... 379
8.3.......... Required method...................................................................................................... 379
Part 8.3—How to assess uncertainty when using method 1 380
8.4.......... Purpose of Part........................................................................................................ 380
8.5.......... General rules about uncertainty estimates for emissions estimates using method 1.. 380
8.6.......... Assessment of uncertainty for estimates of carbon dioxide emissions from combustion of fuels 380
8.7.......... Assessment of uncertainty for estimates of methane and nitrous oxide emissions from combustion of fuels 383
8.8.......... Assessment of uncertainty for estimates of fugitive emissions................................ 384
8.9.......... Assessment of uncertainty for estimates of emissions from industrial process sources 385
8.10........ Assessment of uncertainty for estimates of emissions from waste........................... 386
8.11........ Assessing uncertainty of emissions estimates for a source by aggregating parameter uncertainties 386
Part 8.4—How to assess uncertainty levels when using method 2, 3 or 4 388
8.14........ Purpose of Part........................................................................................................ 388
8.15........ Rules for assessment of uncertainty using method 2, 3 or 4.................................... 388
Chapter 9—Application and transitional provisions 389
9.10........ Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (Energy) Determination 2017................................................................................................. 389
9.11........ Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2018 Update) Determination 2018................................................................................................. 389
9.12........ Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2019 Update) Determination 2019................................................................................................. 389
9.13........ Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2020 Update) Determination 2020................................................................................................. 389
9.14........ Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2021 Update) Determination 2021................................................................................................. 390
9.15........ Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2022 Update) Determination 2022................................................................................................. 390
9.16........ Amendments made by the National Greenhouse and Energy Reporting (Measurement) Amendment (2023 Update) Determination 2023................................................................................................. 390
Schedule 1—Energy content factors and emission factors 391
Part 1—Fuel combustion—solid fuels and certain coal‑based products 391
Part 2—Fuel combustion—gaseous fuels 393
Part 3—Fuel combustion—liquid fuels and certain petroleum‑based products for stationary energy purposes 394
Part 4—Fuel combustion—fuels for transport energy purposes 396
Division 4.1—Fuel combustion—fuels for transport energy purposes 396
Division 4.2—Fuel combustion—liquid fuels for transport energy purposes for post‑2004 vehicles 397
Division 4.3—Fuel combustion—liquid fuels for transport energy purposes for certain trucks 397
Part 5—Consumption of fuels for non‑energy product purposes 398
Part 6—Indirect (scope 2) emission factors and residual mix factors for consumption of electricity 399
Part 7—Energy commodities 400
Schedule 2—Standards and frequency for analysing energy content factor etc for solid fuels 401
Schedule 3—Carbon content factors 405
Part 1—Solid fuels and certain coal‑based products 405
Part 2—Gaseous fuels 406
Part 3—Liquid fuels and certain petroleum‑based products 407
Part 4—Petrochemical feedstocks and products 408
Part 5—Carbonates 409
Schedule 4—Matters to be identified for sources 410
Part 1—Coal mining 410
Part 2—Oil or gas 412
Part 3—Mineral products 423
Part 4—Chemical products 426
Part 5—Metal products 429
Part 6—Waste 433
Part 7—Scope 2 emissions 439
Endnotes 440
Endnote 1—About the endnotes 440
Endnote 2—Abbreviation key 441
Endnote 3—Legislation history 442
Endnote 4—Amendment history 444
Chapter 1—General
Part 1.1—Preliminary
1.1 Name of Determination
This Determination is the National Greenhouse and Energy Reporting (Measurement) Determination 2008.
Division 1.1.1—Overview
1.3 Overview—general
(1) This determination is made under section 10 of the National Greenhouse and Energy Reporting Act 2007. It provides for the measurement of the following:
(a) greenhouse gas emissions arising from the operation of facilities;
(b) the production of energy arising from the operation of facilities;
(c) the consumption of energy arising from the operation of facilities.
Note: Facility has the meaning given by section 9 of the Act.
(2) This determination deals with scope 1 emissions and scope 2 emissions.
Note: Scope 1 emission and scope 2 emission have the meaning given by section 10 of the Act (also see, respectively, regulations 2.23 and 2.24 of the Regulations).
(3) There are 4 categories of scope 1 emissions dealt with in this Determination.
Note: This Determination does not deal with emissions released directly from land management.
(4) The categories of scope 1 emissions are:
(a) fuel combustion, which deals with emissions released from fuel combustion (see Chapter 2); and
(b) fugitive emissions from fuels, which deals with emissions mainly released from the extraction, production, processing and distribution of fossil fuels (see Chapter 3); and
(c) industrial processes emissions, which deals with emissions released from the consumption of carbonates and the use of fuels as feedstock or as carbon reductants, and the emission of synthetic gases in particular cases (see Chapter 4); and
(d) waste emissions, which deals with emissions mainly released from the decomposition of organic material in landfill or other facilities, or wastewater handling facilities (see Chapter 5).
(5) Each of the categories has various subcategories.
1.4 Overview—methods for measurement
(1) This Determination provides methods and criteria for the measurement of the matters mentioned in subsection 1.3(1).
(2) For scope 1 emissions or scope 2 emissions:
(a) method 1 (known as the default method) is derived from the National Greenhouse Accounts methods and is based on national average estimates; and
(b) method 2 is generally a facility specific method using industry practices for sampling and Australian or equivalent standards for analysis; and
(c) method 3 is generally the same as method 2 but is based on Australian or equivalent standards for both sampling and analysis; and
(d) method 4 provides for facility specific measurement of emissions by continuous or periodic emissions monitoring.
Note: Method 4, that applies as indicated by provisions of this Determination, is as set out in Part 1.3.
(3) Data points relevant to the implementation of particular methods are set out in column 3 of the tables in Schedule 4 as ‘matters to be identified’.
Note: Regulations 4.10, 4.11, 4.13, 4.14, 4.15 and 4.17 of the Regulations require these matters to be identified to be included in reports under the Act.
1.5 Overview—energy
Chapter 6 deals with the estimation of the production and consumption of energy.
1.6 Overview—scope 2 emissions
Chapter 7 deals with scope 2 emissions.
1.7 Overview—assessment of uncertainty
Chapter 8 deals with the assessment of uncertainty.
Division 1.1.2—Definitions and interpretation
1.8 Definitions
In this Determination:
2006 IPCC Guidelines means the 2006 IPCC Guidelines for National Greenhouse Gas Inventories published by the IPCC.
ACARP Guidelines means the document entitled Guidelines for the Implementation of NGER Method 2 or 3 for Open Cut Coal Mine Fugitive GHG Emissions Reporting (C20005), published by the Australian Coal Association Research Program in December 2011.
accredited laboratory means a laboratory accredited by the National Association of Testing Authorities or an equivalent member of the International Laboratory Accreditation Cooperation in accordance with AS ISO/IEC 17025:2005, and for the production of calibration gases, accredited to ISO Guide 34:2000.
Act means the National Greenhouse and Energy Reporting Act 2007.
active gas collection means a system of wells and pipes that collect landfill gas through the use of vacuums or pumps.
alternative waste treatment activity means an activity that:
(a) accepts and processes mixed waste using:
(i) mechanical processing; and
(ii) biological or thermal processing; and
(b) extracts recyclable materials from the mixed waste.
alternative waste treatment residue means the material that remains after waste has been processed and organic rich material has been removed by physical screening or sorting by an alternative waste treatment activity that produces compost, soil conditioners or mulch in accordance with:
(a) State or Territory legislation; or
(b) Australian Standard AS 4454:2012.
ANZSIC industry classification and code means an industry classification and code for that classification published in the Australian and New Zealand Standard Industrial Classification (ANZSIC), 2006.
APHA followed by a number means a method of that number issued by the American Public Health Association and, if a date is included, of that date.
API Compendium means the document entitled Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry, published in August 2009 by the American Petroleum Institute.
Note: The API Compendium is available at www.api.org.
applicable State or Territory legislation, for an underground mine, means a law of a State or Territory in which the mine is located that relates to coal mining health and safety, including such a law that prescribes performance‑based objectives, as in force on 1 July 2008.
Note: Applicable State or Territory legislation includes:
· Coal Mine Health and Safety Act 2002 (NSW) and the Coal Mine Health and Safety Regulation 2006 (NSW)
· Coal Mining Safety and Health Act 1999 (Qld) and the Coal Mining Safety and Health Regulation 2001 (Qld).
appropriate standard, for a matter or circumstance, means an Australian standard or an equivalent international standard that is appropriate for the matter or circumstance.
appropriate unit of measurement, in relation to a fuel type, means:
(a) for solid fuels—tonnes; and
(b) for gaseous fuels—metres cubed or gigajoules, except for liquefied natural gas which is kilolitres; and
(c) for liquid fuels other than those mentioned in paragraph (d)—kilolitres; and
(d) for liquid fuels of one of the following kinds—tonnes:
(i) crude oil, plant condensate other natural gas liquids;
(ii) petroleum coke;
(iii) refinery gas and liquids;
(iv) refinery coke;
(v) bitumen:
(vi) waxes;
(vii) carbon black if used as petrochemical feedstock;
(viii) ethylene if used as a petrochemical feedstock;
(ix) petrochemical feedstock mentioned in item 57 of Schedule 1 to the Regulations.
AS or Australian standard followed by a number (for example, AS 4323.1—1995) means a standard of that number issued by Standards Australia Limited and, if a date is included, of that date.
ASTM followed by a number (for example, ASTM D6347/D6347M‑99) means a standard of that number issued by ASTM International and, if a date is included, of that date.
Australian legal unit of measurement has the meaning given by the National Measurement Act 1960.
base of the low gas zone means the part of the low gas zone worked out in accordance with section 3.25A.
basin means a geological basin named in the Australian Geological Provinces Database.
Note: The Australian Geological Provinces Database is available at www.ga.gov.au.
biodiesel has the meaning given by the Regulations.
biogenic carbon fuel means energy that is:
(a) derived from plant and animal material, such as wood from forests, residues from agriculture and forestry processes and industrial, human or animal wastes; and
(b) not embedded in the earth for example, like coal oil or natural gas.
biological treatment of solid waste:
(a) means an alternative waste treatment activity consisting of a composting or anaerobic digestion process in which organic matter in solid waste is broken down by microorganisms; but
(b) does not include solid waste disposal in a landfill.
Note: Chapter 5 (waste) deals with solid waste disposal in a landfill as well as the biological treatment of solid waste (whether at a landfill or at a facility elsewhere).
biomethane has the meaning given by the Regulations.
blended fuel means fuel that is a blend of fossil and biogenic carbon fuels.
briquette means an agglomerate formed by compacting a particulate material in a briquette press, with or without added binder material.
calibrated to a measurement requirement, for measuring equipment, means calibrated to a specific characteristic, for example a unit of weight, with the characteristic being traceable to:
(a) a measurement requirement provided for under the National Measurement Act 1960 or any instrument under that Act for that equipment; or
(b) a measurement requirement under an equivalent standard for that characteristic.
captured for enhanced oil recovery: a greenhouse gas is captured for enhanced oil recovery if it is captured and transferred to the holder of an enhanced oil recovery authority for injection into a geological formation, such as a natural reservoir, to further oil or gas production activities and is not captured for permanent storage.
captured for permanent storage, in relation to a greenhouse gas, has the meaning given by section 1.19A.
CEM or continuous emissions monitoring means continuous monitoring of emissions in accordance with Part 1.3.
CEN/TS followed by a number (for example, CEN/TS 15403) means a technical specification (TS) of that number issued by the European Committee for Standardization and, if a date is included, of that date.
city gate means a distribution hub where gas is reduced in pressure before it enters the lower pressure, smaller diameter, distribution pipeline network.
CO2‑e means carbon dioxide equivalence.
CO2 stimulation means using carbon dioxide as a fluid in well stimulation treatment which enhances oil and gas production or recovery by increasing the permeability of the formation.
coal seam methane has the same meaning as in the Regulations.
COD or chemical oxygen demand means the total material available for chemical oxidation (both biodegradable and non‑biodegradable) measured in tonnes.
compressed natural gas has the meaning given by the Regulations.
core sample means a cylindrical sample of the whole or part of a strata layer, or series of strata layers, obtained from drilling using a coring barrel with a diameter of between 50 mm and 2 000 mm.
crude oil has the meaning given by the Regulations.
crude oil transport means the transportation of marketable crude oil to heavy oil upgraders and refineries by means that include the following:
(a) pipelines;
(b) marine tankers;
(c) tank trucks;
(d) rail cars.
decommissioned underground mine has the meaning given by the Regulations.
detection agent has the same meaning as in the Offshore Petroleum and Greenhouse Gas Storage Act 2006.
documentary standard means a published standard that sets out specifications and procedures designed to ensure that a material or other thing is fit for purpose and consistently performs in the way it was intended by the manufacturer of the material or thing.
domain, of an open cut mine, means an area, volume or coal seam in which the variability of gas content and the variability of gas composition in the open cut mine have a consistent relationship with other geological, geophysical or spatial parameters located in the area, volume or coal seam.
dry wood has the meaning given by the Regulations.
efficiency method has the meaning given by subsection 2.70(2).
EN followed by a number (for example, EN 15403) means a standard of that number issued by the European Committee for Standardization and, if a date is included, of that date.
enclosed composting activity means a semi‑enclosed or enclosed alternative waste or composting technology where the composting process occurs within a reactor that:
(a) has hard walls or doors on all 4 sides; and
(b) sits on a floor; and
(c) has a permanent positive or negative aeration system.
energy content factor, for a fuel, means gigajoules of energy per unit of the fuel measured as gross calorific value.
enhanced oil recovery authority means a licence, lease or approval by or under a law of the Commonwealth, State or Territory which authorises the injection of one or more greenhouse gases into one or more geological formations, such as a natural reservoirs, to further oil or gas production activities.
equivalent leak detection standard, means a standard or documented approach that:
(a) has equivalent or higher integrity than the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America or optical gas imaging in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; and
(b) has equivalent or higher sensitivity for detecting leaks than:
(i) 60 grams per hour in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; or
(ii) 10,000 parts per million or greater in accordance with the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America.
estimator, of fugitive emissions from an open cut mine using method 2 under section 3.21 or method 3 under section 3.26, means:
(a) an individual who has the minimum qualifications of an estimator set out in the ACARP Guidelines; or
(b) individuals who jointly have those minimum qualifications.
extraction area, in relation to an open cut mine, is the area of the mine from which coal is extracted.
feedstock has the meaning given by the Regulations.
ferroalloy has the meaning given by subsection 4.69(2).
flaring means the combustion of fuel for a purpose other than producing energy.
Example: The combustion of methane for the purpose of complying with health, safety and environmental requirements.
fuel means a substance mentioned in column 2 of an item in Schedule 1 to the Regulations other than a substance mentioned in items 58 to 66.
fuel oil has the meaning given by the Regulations.
fugitive emissions means greenhouse gas emissions that are:
(a) released in connection with, or as a consequence of, the extraction, processing, storage or delivery of fossil fuel; and
(b) not released from the combustion of fuel for the production of useable heat or electricity.
gas bearing strata is coal and carbonaceous rock strata:
(a) located in an open cut mine; and
(b) that has a relative density of less than 1.95 g/cm3.
gaseous fuel means a fuel mentioned in column 2 of items 17 to 30 of Schedule 1 to the Regulations.
gas stream means the flow of gas subject to monitoring under Part 1.3.
gassy mine means an underground mine that has at least 0.1% methane in the mine’s return ventilation.
Global Warming Potential means, in relation to a greenhouse gas mentioned in column 2 of an item in the table in regulation 2.02 of the Regulations, the value mentioned in column 4 for that item.
GPA followed by a number means a standard of that number issued by the Gas Processors Association and, if a date is included, of that date.
green and air dried wood has the meaning given by the Regulations.
greenhouse gas stream means a stream consisting of a mixture of any or all of the following substances captured for injection into, and captured for permanent storage in, a geological formation:
(a) carbon dioxide, whether in a gaseous or liquid state;
(b) a greenhouse gas other than carbon dioxide, whether in a gaseous or liquid state;
(c) one or more incidental greenhouse gas‑related substances, whether in a gaseous or liquid state, that relate to either or both of the greenhouse gases mentioned in paragraph (a) and (b);
(d) a detection agent, whether in a gaseous or liquid state;
so long as:
(e) the mixture consists overwhelmingly of either or both of the greenhouse gases mentioned in paragraphs (a) and (b); and
(f) if the mixture includes a detection agent—the concentration of the detection agent in the mixture is not more than the concentration prescribed in relation to the detection agent for the purposes of subparagraph (vi) of paragraph (c) of the definition of greenhouse gas substance in section 7 of the Offshore Petroleum and Greenhouse Gas Storage Act 2006.
Note: A greenhouse gas is captured for permanent storage in a geological formation if the gas is captured by, or transferred to, the holder of a licence, lease or approval mentioned in section 1.19A, under a law mentioned in that section, for the purpose of being injected into a geological formation (however described) under the licence, lease or approval.
gross vehicle mass means the tare weight of the vehicle plus its maximum carrying capacity, excluding trailers.
GST group has the same meaning as in the Fuel Tax Act 2006.
GST joint venture has the same meaning as in the Fuel Tax Act 2006.
GWPmethane means the Global Warming Potential of methane.
heavy duty vehicle means a vehicle with a gross vehicle mass of more than 4.5 tonnes.
higher method has the meaning given by subsection 1.18(5).
hydrofluorocarbons has the meaning given by section 4.99.
ideal gas law means the state of a hypothetical ideal gas in which the amount of gas is determined by its pressure, volume and temperature.
IEC followed by a number (for example, IEC 17025:2005) means a standard of that number issued by the International Electrotechnical Commission and, if a date is included, of that date.
incidental, for an emission, has the meaning given by subregulation 4.27(5) of the Regulations.
incidental greenhouse gas‑related substance, in relation to a greenhouse gas that is captured from a particular source material, means:
(a) any substance that is incidentally derived from the source material; or
(b) any substance that is incidentally derived from the capture; or
(c) if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is transported—any substance that is incidentally derived from the transportation; or
(d) if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is injected into a part of a geological formation—any substance that is incidentally derived from the injection; or
(e) if the captured greenhouse gas, whether in a pure form or in a mixture with other substances, is stored in a part of a geological formation—any substance that is incidentally derived from the storage.
independent expert, in relation to an operator of a landfill, means a person who:
(a) is independent of the operator of the landfill; and
(b) has relevant expertise in estimating or monitoring landfill surface gas.
inert waste means waste materials that contain no more than a negligible volume of degradable organic carbon and includes the following waste:
(a) concrete;
(b) metal;
(c) plastic;
(d) glass;
(e) asbestos concrete;
(f) soil.
integrated metalworks has the meaning given by subsection 4.64(2).
invoice includes delivery record.
IPCC is short for Intergovernmental Panel on Climate Change established by the World Meteorological Organization and the United Nations Environment Programme.
ISO followed by a number (for example, ISO 10396:2007) means a standard of that number issued by the International Organization of Standardization and, if a date is included, of that date.
Leak Detection and Repair Program or LDAR program means a system of procedures used at a facility to monitor, locate and repair leaking components in order to minimize emissions.
leaker, in relation to a component subject to an LDAR program, means:
(a) if optical gas imaging is used, a leaker is detected at a sensitivity of 60 grams per hour in accordance with paragraph 98.234(a)(1) of Title 40, Part 98 of the Code of Federal Regulations, United States of America; and
(b) if the method outlined in USEPA Method 21—Determination of organic volatile compound leaks, as set out in Appendix A‑7 of Title 40, Part 60 of the Code of Federal Regulations, United States of America is used, a leaker is detected if 10,000 parts per million or greater is measured consistent with that method; and
(c) if an equivalent leak detection standard is used, a leaker is detected at the sensitivity set for that standard.
Note: Under the definition of equivalent leak detection standard, the sensitivity must be equivalent or higher than the approaches in paragraph (a) or (b).
legacy emissions has the same meaning as in the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015.
legacy waste means waste deposited at a landfill before 1 July 2016.
light duty vehicle means a vehicle other than a heavy duty vehicle.
liquefied natural gas has the same meaning as in the Regulations.
liquefied natural gas station means the plant and equipment used in the natural gas liquefaction, storage and transfer of liquefied natural gas, and includes:
(a) all onshore or offshore equipment that receives natural gas, liquefies and stores liquefied natural gas, and transfers the liquefied natural gas to a transportation system; and
(b) equipment that receives imported or transported liquefied natural gas, stores liquefied natural gas, re-gasifies liquefied natural gas, and delivers re-gasified natural gas to a natural gas transmission or distribution system.
liquefied petroleum gas has the same meaning as in the Regulations.
liquid fuel means a fuel mentioned in column 2 of items 31 to 54 of Schedule 1 to the Regulations.
lower method has the meaning given by subsection 1.18(6).
low gas zone means the part of the gas bearing strata of an open cut mine:
(a) that is located immediately below the original surface of the mine and above the base of the low gas zone; and
(b) the area of which is worked out by working out the base of the low gas zone.
main electricity grid has the meaning given by subsection 7.2(4).
marketable crude oil includes:
(a) conventional crude oil; and
(b) heavy crude oil; and
(c) synthetic crude oil; and
(d) bitumen.
method means a method specified in this determination for estimating emissions released from the operation of a facility in relation to a source.
municipal materials has the meaning given by the Regulations.
municipal solid waste class I means waste from domestic premises, council collections and other municipal sources where:
(a) the collection of organic waste on a regular basis in a dedicated bin is not provided to residents of the municipality as a standard practice; or
(b) the collection of organic waste on a regular basis in a dedicated bin provided to residents of the municipality cannot be confirmed as standard practice.
municipal solid waste class II means waste from domestic premises, council collections and other municipal sources where a bin dedicated for garden waste is:
(a) provided to residents of the municipality as a standard practice; and
(b) collected on a regular basis.
N/A means not available.
National Greenhouse Accounts means the set of national greenhouse gas inventories, including the National Inventory Report 2005, submitted by the Australian government to meet its reporting commitments under the United Nations Framework Convention on Climate Change and the 1997 Kyoto Protocol to that Convention.
natural gas has the meaning given by the Regulations.
natural gas distribution means the transport of pipeline natural gas over a combination of natural gas distribution pipelines from a city gate to customer delivery points.
natural gas distribution pipelines mean pipelines for the conveyance of pipeline natural gas that:
(a) are identified as a distribution pipeline in an access arrangement applicable to the pipeline; or
(b) meet both of the following:
(i) have a maximum design pressure of 1,050 kPa or less; and
(ii) are not natural gas gathering and boosting pipelines.
natural gas gathering and boosting means the activity to collect unprocessed natural gas or coal seam methane from gas wellheads and to compress, dehydrate, sweeten, or transport the gas through natural gas gathering and boosting pipelines to a natural gas processing station, a natural gas transmission pipeline or a natural gas distribution pipeline.
natural gas gathering and boosting pipeline means a pipeline for the conveyance of gas that:
(a) contains unprocessed natural gas or coal seam methane; and
(b) pertains to the activity of natural gas gathering and boosting.
Note: Such pipelines can operates at high or low pressures
natural gas gathering and boosting station means one or more pieces of plant and equipment used in natural gas gathering and boosting at a single location that operates as a unit in the natural gas gathering and boosting activity. The plant and equipment may include any of the following:
(a) compressors;
(b) generators;
(c) dehydrators;
(d) storage vessels;
(e) acid gas removal units;
(f) engines;
(g) boilers;
(h) heaters;
(i) flares;
(j) separation and processing equipment;
(k) associated storage or measurement vessels;
(l) equipment on, or associated with, an enhanced oil recovery well pad using CO2 or gas injection.
Note: The single location that operates as a unit will generally be known as a facility, station or node for operational purposes. It is not expected that stations will be defined differently for operational purposes and emissions accounting purposes.
natural gas liquefaction, storage and transfer means the activity to collect and liquefy natural gas and to store and transfer liquefied natural gas to a transportation system.
natural gas liquids has the meaning given by the Regulations.
natural gas processing station means the plant and equipment used in the natural gas processing in a single location, and includes:
(a) liquids recovery plant and equipment where the separation of natural gas liquids or non-methane gases from unprocessed natural gas or coal seam methane occurs; and
(b) liquids recovery plant and equipment where the separation of natural gas liquids into one or more component mixtures occur; and
(c) gas separation trains where the removal of acidic gases from unprocessed natural gas or coal seam methane occurs;
Note: The separation includes one or more of the following: forced extraction of natural gas liquids, sulphur and carbon dioxide removal, fractionation of natural gas liquids, or the capture of CO2 separated from unprocessed natural gas and coal seam methane streams.
natural gas processing means one or both of the following activities:
(a) the separation of natural gas liquids or non-methane gases from unprocessed natural gas or coal seam methane;
(b) the separation of natural gas liquids into one or more component mixtures.
Note: The separation includes one or more of the following: forced extraction of natural gas liquids, sulphur and carbon dioxide removal, fractionation of natural gas liquids, or the capture of CO2 separated from natural gas streams.
natural gas production includes offshore natural gas production and onshore natural gas production.
natural gas storage means the activity to store unprocessed natural gas, coal seam methane or natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas).
natural gas storage station means the plant and equipment used in natural gas storage, and includes:
(a) subsurface storage, such as depleted gas or oil reservoirs that store gas; and
(b) the equipment to undertake natural gas underground storage processes and operations (including compression, dehydration and flow measurement, but excluding natural gas transmission pipelines); and
(c) all the wellheads connected to the compression units located at the station that inject and recover natural gas into and from the underground reservoirs.
natural gas transmission means transmission of natural gas or plant condensate through one or more natural gas transmission pipelines from a natural gas processing station or a natural gas gathering and boosting network to any of the following:
(a) a natural gas distribution network;
(b) another natural gas processing station;
(c) a liquefied natural gas station;
(d) a large industrial facility, such as a power station.
natural gas transmission pipeline means a pipeline for the conveyance of pipeline natural gas or plant condensate that:
(a) is licensed as a transmission pipeline under a Commonwealth, State or Territory law; and
(b) has a maximum design pressure exceeding 1,050 kPa; and
(c) is not a natural gas distribution pipeline or a natural gas gathering and boosting pipeline.
non‑gassy mine means an underground mine that has less than 0.1% methane in the mine’s return ventilation.
non‑legacy waste means waste deposited at a landfill on or after 1 July 2016.
offshore natural gas production means the activity to produce, extract, recover, lift, stabilise, separate or treat unprocessed natural gas, condensate or coal seam methane on offshore submerged lands, including well workovers.
offshore platform includes:
(a) any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses plant and equipment to do either or both of the following:
(i) extract unprocessed natural gas and condensate from the ocean or lake floor;
(ii) transfers such unprocessed natural gas and condensate to storage, transport vessels, or onshore; and
(b) secondary platform structures connected to the platform structure via walkways, and
(c) storage tanks associated with the platform structure; and
(d) floating production and storage offloading equipment; and
(e) submerged wellhead production structures.
offshore platform (shallow water) means an offshore platform standing in less than 200 metres of water.
offshore platform (deep water) means an offshore platform standing in at least 200 metres of water.
oil or gas exploration and development means the activity to explore for oil and gas resources and test, appraise, drill, develop and complete wells for oil and gas resources and includes the following actions:
(a) oil well drilling;
(b) gas well drilling;
(c) drill stem testing;
(e) well appraisals;
(f) development drilling;
(g) well completions;
(h) well workovers associated with the actions in the paragraphs above.
onshore natural gas production means the activity to produce, extract, recover, lift, stabilise, separate or treat unprocessed natural gas, condensate or coal seam methane on land, including well workovers.
onshore natural gas wellhead means the gas wellhead.
open cut mine:
(a) means a mine in which the overburden is removed from coal seams to allow coal extraction by mining that is not underground mining; and
(b) for method 2 in section 3.21 or method 3 in section 3.26—includes a mine of the kind mentioned in paragraph (a):
(i) for which an area has been established but coal production has not commenced; or
(ii) in which coal production has commenced.
PEM or periodic emissions monitoring means periodic monitoring of emissions in accordance with Part 1.3.
Perfluorocarbon protocol means the Protocol for Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) Emissions from Primary Aluminium Production published by the United States Environmental Protection Agency and the International Aluminium Institute.
petroleum based greases has the meaning given by regulation 1.03 of the Regulations.
petroleum based oils has the meaning given by the Regulations.
petroleum coke has the meaning given by the Regulations.
phytocap means an evapotranspiration landfill capping system that makes use of soil and vegetation to store and release surface water.
pipeline natural gas means natural gas that is suitable for market consumption.
plant condensate has the meaning given by the Regulations.
post‑mining activities, in relation to a mine, is the handling, stockpiling, processing and transportation of coal extracted from the mine.
primary wastewater treatment plant:
(a) means a treatment facility at which wastewater undergoes physical screening, degritting and sedimentation; and
(b) does not include a treatment facility at which any kind of nitrification or denitrification treatment process occurs.
principal activity, in relation to a facility, means the activity that:
(a) results in the production of a product or service that is produced for sale on the market; and
(b) produces the most value for the facility out of any of the activities forming part of the facility.
produced water means the water that is either:
(a) pumped from coal seams or unprocessed gas reservoirs during natural gas production or natural gas gathering and boosting; or
(b) pumped from wells during crude oil production or oil and gas exploration and development.
pyrolysis of coal means the decomposition of coal by heat.
raw sugar has the meaning given by Chapter 17 of Section IV of Schedule 3 to the Customs Tariff Act 1995.
reductant:
(a) means a reducing agent or substance:
(i) that causes another substance to undergo reduction; and
(ii) that is oxidised while causing the substance to undergo reduction; and
(b) does not include fuels that are combusted only to produce energy.
refinery gases and liquids has the meaning given by the Regulations.
Regulations means the National Greenhouse and Energy Reporting Regulations 2008.
relevant person means a person mentioned in paragraph 1.19A(a), (b), (c), (d), (e) or (f).
renewable aviation kerosene has the meaning given by the Regulations.
renewable diesel has the meaning given by the Regulations.
run‑of‑mine coal means coal that is produced by mining operations before screening, crushing or preparation of the coal has occurred.
scope 1 emissions has the same meaning as in the Regulations.
scope 2 emissions has the same meaning as in the Regulations.
separate instance of a source has the meaning given by section 1.9A.
separate occurrence of a source has the meaning given by section 1.9B.
shale gas means a substance that:
(a) consists of:
(i) naturally occurring hydrocarbons; or
(ii) a naturally occurring mixture of hydrocarbons and non‑hydrocarbons; and
(b) consists mainly of methane; and
(c) is drained from shale formations.
shredder flock means the residual waste generated from the process of scrap metal processing that ends up in landfill.
sludge biogas has the meaning given by the Regulations.
sludge lagoon means a component of a wastewater treatment system that:
(a) is used to stabilise and dry excess or wasted sludge from the liquid or solid phase treatment train of a wastewater treatment plant; and
(b) involves biodegradation of COD in the form of sludge and the use of ambient climatic factors to reduce the moisture content of the sludge.
solid fuel means a fuel mentioned in column 2 of items 1 to 16 of Schedule 1 to the Regulations.
source has the meaning given by section 1.10.
specified taxable fuel has the meaning given by regulation 3.30 of the Clean Energy Regulations 2011.
standard includes a protocol, technical specification or USEPA method.
standard conditions has the meaning given by subsection 2.32(7).
sulphite lyes has the meaning given by the Regulations.
supply means supply by way of sale, exchange or gift.
synthetic gas generating activities has the meaning given by subsections 4.100(1) and (2).
tight gas means a substance that:
(a) consists of:
(i) naturally occurring hydrocarbons; or
(ii) a naturally occurring mixture of hydrocarbons and non‑hydrocarbons; and
(b) consists mainly of methane; and
(c) is drained from low permeability sandstone and limestone reservoirs.
uncertainty protocol means the publication known as the GHG protocol guidance on uncertainty assessment in GHG inventories and calculating statistical parameter uncertainty (September 2003) v1.0 issued by the World Resources Institute and the World Business Council for Sustainable Development.
underground mine means a coal mine that allows extraction of coal by mining at depth, after entry by shaft, adit or drift, without the removal of overburden.
USEPA followed by a reference to a method (for example, Method 3C) means a standard of that description issued by the United States Environmental Protection Agency.
waxes has the meaning given by the Regulations.
well completion means the period that:
(a) begins on the initial gas flow in the well; and
(b) ends on whichever of the following occurs first:
(i) well shut in; or
(ii) continuous gas flow from the well to a flow line or a storage vessel for collection.
well workover means activities performed to restore or increase production which can include any or all of the following processes:
(a) well venting;
(b) tubing maintenance;
(c) air clean out;
(d) hydraulic fracturing and recovery;
(e) well unloading.
wet weight, in relation to waste, is the weight of material that has not been treated to remove moisture.
year means a financial year.
Note: The following expressions in this Determination are defined in the Act:
· carbon dioxide equivalence
· consumption of energy (see also regulation 2.26 of the Regulations)
· energy
· facility
· greenhouse gas
· group
· industry sector
· operational control
· potential greenhouse gas emissions
· production of energy (see also regulation 2.25 of the Regulations)
· registered corporation
· scope 1 emission (see also regulation 2.23 of the Regulations)
· scope 2 emission (see also regulation 2.24 of the Regulations).
1.9 Interpretation
(1) In this Determination, a reference to emissions is a reference to emissions of greenhouse gases.
(2) In this Determination, a reference to a gas type (j) is a reference to a greenhouse gas.
(3) In this Determination, a reference to a facility that is constituted by an activity is a reference to the facility being constituted in whole or in part by the activity.
Note: Section 9 of the Act defines a facility as an activity or series of activities.
(4) In this Determination, a reference to a standard, instrument or other writing (other than a Commonwealth Act or Regulations) however described, is a reference to that standard, instrument or other writing as in force on 1 January 2020.
1.9A Meaning of separate instance of a source
If 2 or more different activities of a facility have the same source of emissions, each activity is taken to be a separate instance of the source if the activity is performed by a class of equipment different from that used by another activity.
Example: The combustion of liquefied petroleum gas in the engines of distribution vehicles of the facility operator and the combustion of liquid petroleum fuel in lawn mowers at the facility, although the activities have the same source of emissions, are taken to be a separate instance of the source as the activities are different and the class of equipment used to perform the activities are different.
1.9B Meaning of separate occurrence of a source
(1) If 2 or more things at a facility have the same source of emissions, each thing may be treated as a separate occurrence of the source.
Example: The combustion of unprocessed natural gas in 2 or more gas flares at a facility may be treated as a separate occurrence of the source (natural gas production or processing—flaring).
(2) If a thing at a facility uses 2 or more energy types, each energy type may be treated as a separate occurrence of the source.
Example: The combustion of diesel and petrol in a vehicle at a facility may be treated as a separate occurrence of the source (fuel combustion).
1.10 Meaning of source
(1) A thing mentioned in the column headed ‘Source of emissions’ of the following table is a source.
| Item | Category of source | Source of emissions |
| 1 | Fuel combustion | |
| 1A | | Fuel combustion |
| 2 | Fugitive emissions | |
| 2A | | Underground mines |
| 2B | | Open cut mines |
| 2C | | Decommissioned underground mines |
| 2D | | Oil or gas exploration and development—flaring |
| 2E | | Oil or gas exploration and development (other than flaring) |
| 2F | | Crude oil production |
| 2G | | Crude oil transport |
| 2H | | Crude oil refining |
| 2I | | Onshore natural gas production (other than emissions that are vented or flared) |
| 2J | | Offshore natural gas production (other than emissions that are vented or flared) |
| 2K | | Natural gas gathering and boosting (other than emissions that are vented or flared) |
| 2L | | Produced water from oil and gas exploration and development, crude oil production, natural gas production or natural gas gathering and boosting (other than emissions that are vented or flared) |
| 2M | | Natural gas processing (other than emissions that are vented or flared) |
| 2N | | Natural gas transmission (other than flaring) |
| 2O | | Natural gas storage (other than emissions that are vented or flared) |
| 2P | | Natural gas liquefaction, storage and transfer (other than emissions that are vented or flared) |
| 2Q | | Natural gas distribution (other than flaring) |
| 2R | | Onshore natural gas production—venting |
| 2S | | Offshore natural gas production—venting |
| 2T | | Onshore natural gas production—flaring |
| 2U | | Offshore natural gas production—flaring |
| 2V | | Natural gas gathering and boosting—venting |
| 2W | | Natural gas gathering and boosting—flaring |
| 2X | | Natural gas processing—venting |
| 2Y | | Natural gas processing—flaring |
| 2Z | | Natural gas transmission—flaring |
| 2ZA | | Natural gas storage—venting |
| 2ZB | | Natural gas storage—flaring |
| 2ZC | | Natural gas liquefaction, storage and transfer—venting |
| 2ZE | | Natural gas liquefaction, storage and transfer—flaring |
| 2ZF | | Natural gas distribution—flaring |
| 2ZG | | Carbon capture and storage |
| 2ZH | | Enhanced oil recovery |
| 3 | Industrial processes | |
| 3A | | Cement clinker production |
| 3B | | Lime production |
| 3C | | Use of carbonates for the production of a product other than cement clinker, lime or soda ash |
| 3D | | Soda ash use |
| 3E | | Soda ash production |
| 3F | | Ammonia production |
| 3G | | Nitric acid production |
| 3H | | Adipic acid production |
| 3I | | Carbide production |
| 3J | | Chemical or mineral production, other than carbide production, using a carbon reductant or carbon anode |
| 3JA | | Sodium cyanide production |
| 3JB | | Hydrogen production |
| 3K | | Iron, steel or other metal production using an integrated metalworks |
| 3L | | Ferroalloys production |
| 3M | | Aluminium production |
| 3N | | Other metals production |
| 3O | | Emissions of hydrofluorocarbons and sulphur hexafluoride gases |
| 4 | Waste | |
| 4A | | Solid waste disposal on land |
| 4AA | | Biological treatment of solid waste |
| 4B | | Wastewater handling (industrial) |
| 4C | | Wastewater handling (domestic or commercial) |
| 4D | | Waste incineration |
(2) The extent of the source is as provided for in this Determination.
Part 1.2—General
1.11 Purpose of Part
This Part provides for general matters as follows:
(a) Division 1.2.1 provides for the measurement of emissions and energy and also deals with standards;
(b) Division 1.2.2 provides for methods for measuring emissions;
(c) Division 1.2.3 provides requirements in relation to carbon capture and storage.
Division 1.2.1—Measurement and standards
1.12 Measurement of emissions and energy
(1) The measurement of emissions released from the operation of a facility is to be done by estimating the emissions in accordance with this Determination.
(2) The measurement of the production and consumption of energy from the operation of a facility is to be done by estimating the production and consumption of energy in accordance with this Determination.
1.13 General principles for measuring emissions and energy
Estimates for this Determination must be prepared in accordance with the following principles:
(a) transparency—emission and energy estimates must be documented and verifiable;
(b) comparability—emission and energy estimates using a particular method and produced by a registered corporation or registered person in an industry sector must be comparable with emission and energy estimates produced by similar corporations or persons in that industry sector using the same method and consistent with the emission and energy estimates published by the Department in the National Greenhouse Accounts;
(c) accuracy—having regard to the availability of reasonable resources by a registered corporation or registered person and the requirements of this Determination, uncertainties in emission and energy estimates must be minimised and any estimates must neither be over nor under estimates of the true values at a 95% confidence level;
(d) completeness—all identifiable emission sources mentioned in section 1.10 must be accounted for and production and consumption of all identifiable fuels and energy commodities listed in Schedule 1 of the Regulations must be accounted for, subject to any applicable reporting thresholds.
1.14 Assessment of uncertainty
The estimate of emissions released from the operation of a facility must include assessment of uncertainty in accordance with Chapter 8.
1.15 Units of measurement
(1) For this Determination, measurements of fuel must be converted as follows:
(a) for solid fuel, to tonnes; and
(b) for liquid fuels, to kilolitres unless otherwise specified; and
(c) for gaseous fuels, to cubic metres, corrected to standard conditions, unless otherwise specified.
(2) For this Determination, emissions of greenhouses gases must be estimated in CO2‑e tonnes.
(3) Measurements of energy content must be converted to gigajoules.
(4) The National Measurement Act 1960, and any instrument made under that Act, must be used for conversions required under this section.
1.16 Rounding of amounts
(1) If:
(a) an amount is worked out under this Determination; and
(b) the number is not a whole number;
then:
(c) the number is to be rounded up to the next whole number if the number at the first decimal place equals or exceeds 5; and
(d) rounded down to the next whole number if the number at the first decimal place is less than 5.
(2) Subsection (1) applies to amounts that are measures of emissions or energy.
1.17 Status of standards
If there is an inconsistency between this Determination and a documentary standard, this Determination prevails to the extent of the inconsistency.
Division 1.2.2—Methods
1.18 Method to be used for a separate occurrence of a source
(1) This section deals with the number of methods that may be used to estimate emissions of a particular greenhouse gas released, in relation to a separate occurrence of a source, from the operation of a facility.
(1A) Subsections (2) and (3) do not apply to a facility if:
(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611) and the generating unit used to perform the principal activity:
(i) does not have the capacity to generate, in a reporting year, the amount of electricity mentioned in subparagraph 2.3(3)(b)(i); and
(ii) generates, in a reporting year, less than or equal to the amount of electricity mentioned in subparagraph 2.3(3)(b)(ii); or
(b) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611) and the generating unit used to perform the principal activity:
(i) does not have the capacity to generate, in a reporting year, the amount of electricity mentioned in subparagraph 2.19(3)(b)(i); and
(ii) generates, in a reporting year, less than or equal to the amount of electricity mentioned in subparagraph 2.19(3)(b)(ii).
(2) Subject to subsection (3) and (3A), one method for the separate occurrence of a source must be used for 4 reporting years unless another higher method is used.
(3) If:
(a) at a particular time, a method is being used to estimate emissions in relation to the separate occurrence of a source; and
(b) either:
(i) in the preceding 4 reporting years before that time, only that method has been used to estimate the emissions from the separate occurrence of the source; or
(ii) a registered corporation or registered person certifies in writing that the method used was found to be non‑compliant during an external audit of the separate occurrence of the source;
then a lower method may be used to estimate emissions in relation to the separate occurrence of the source from that time.
(3A) If section 22AA of the Act applies to a person, a lower method may be used to estimate emissions in relation to the source for the purposes of reporting under section 22AA.
(4) In this section, reporting year, in relation to a source from the operation of a facility under the operational control of a registered corporation and entities that are members of the corporation’s group, means a year that the registered corporation is required to provide a report under section 19 of the Act in relation to the facility
(5) Higher method, is:
(a) a prescribed alternative method; or
(b) in relation to a method (the original method) being used to estimate emissions in relation to a separate occurrence of a source, a method for the source with a higher number than the number of the original method.
(6) Lower method, is:
(a) a default method; or
(b) in relation to a method (the original method) being used to estimate emissions in relation to a separate occurrence of a source, a method for the source with a lower number than the number of the original method.
1.18A Conditions—persons preparing report must use same method
(1) This section applies if a person is required, under section 19, 22A, 22AA, 22E, 22G or 22X of the Act (a reporting provision), to provide a report to the Regulator for a reporting year or part of a reporting year (the reporting period).
(2) For paragraph 10(3)(c) of the Act:
(a) the person must, before 31 August in the year immediately following the reporting year, notify any other person required, under a reporting provision, to provide a report to the Regulator for the same facility of the method the person will use in the report; and
(b) each person required to provide a report to the Regulator for the same facility and for the same reporting period must, before 31 October in the year immediately following the reporting year, take all reasonable steps to agree on a method to be used for each report provided to the Regulator for the facility and for the reporting period.
(3) If the persons mentioned in paragraph (2)(b) do not agree on a method before 31 October in the year immediately following the reporting year, each report provided to the Regulator for the facility and for the reporting period must use the method:
(a) that was used in a report provided to the Regulator for the facility for the previous reporting year (if any); and
(b) that will, of all the methods used in a report provided to the Regulator for the facility for the previous reporting year, result in a measurement of the largest amount of emissions for the facility for the reporting year.
(4) In this section, a reference to a method is a reference to a method or available alternative method, including the options (if any) included in the method or available alternative method.
Note 1: Reporting year has the meaning given by the Regulations.
Note 2: An example of available alternative methods is method 2 in section 2.5 and method 2 in section 2.6.
Note 3: An example of options included within a method is paragraphs 3.36(a) and (b), which provide 2 options of ways to measure the size of mine void volume.
Note 4: An example of options included within an available alternative method is the options for identifying the value of the oxidation factor (OFs) in subsection 2.5(3).
1.19 Temporary unavailability of method
(1) The procedure set out in this section applies if, during a reporting year, a method for a separate occurrence of a source cannot be used because of a mechanical or technical failure of equipment or a failure of measurement systems during a period (the down time).
(2) For each day or part of a day during the down time, the estimation of emissions from the separate occurrence of a source must be consistent with the principles in section 1.13.
(3) Subsection (2) only applies for a maximum of 6 weeks in a year. This period does not include down time taken for the calibration of the equipment.
(4) If down time is more than 6 weeks in a year, the registered corporation or registered person must inform the Regulator, in writing, of the following:
(a) the reason why down time is more than 6 weeks;
(b) how the corporation or person plans to minimise down time;
(c) how emissions have been estimated during the down time.
(5) The information mentioned in subsection (4) must be given to the Regulator within 6 weeks after the day when down time exceeds 6 weeks in a year.
(6) The Regulator may require a registered corporation or registered person to use method 1 to estimate emissions during the down time if:
(a) method 2, 3 or 4 has been used to estimate emissions for the separate occurrence of a source; and
(b) down time is more than 6 weeks in a year.
Division 1.2.3—Requirements in relation to carbon capture and storage
1.19A Meaning of captured for permanent storage
For this Determination, a greenhouse gas is captured for permanent storage only if it is captured by, or transferred to:
(a) the registered holder of a greenhouse gas injection licence under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 for the purpose of being injected into an identified greenhouse gas storage formation under the licence in accordance with that Act; or
(b) the holder of an injection and monitoring licence under the Greenhouse Gas Geological Sequestration Act 2008 (Vic) for the purpose of being injected into an underground geological formation under the licence in accordance with that Act; or
(c) the registered holder of a greenhouse gas injection licence under the Offshore Petroleum and Greenhouse Gas Storage Act 2010 (Vic) for the purpose of being injected into an identified greenhouse gas storage formation under the licence in accordance with that Act; or
(d) the holder of a GHG injection and storage lease under the Greenhouse Gas Storage Act 2009 (Qld) for the purpose of being injected into a GHG stream storage site under the lease in accordance with that Act; or
(e) the holder of an approval under the Barrow Island Act 2003 (WA) for the purpose of being injected into an underground reservoir or other subsurface formation in accordance with that Act; or
(f) the holder of a gas storage licence under the Petroleum and Geothermal Energy Act 2000 (SA) for the purpose of being injected into a natural reservoir under the licence in accordance with that Act.
1.19B Deducting greenhouse gas that is captured for permanent storage
(1) If a provision of this Determination provides that an amount of a greenhouse gas that is captured for permanent storage may be deducted in the estimation of emissions under the provision, then the amount of the greenhouse gas may be deducted only if:
(a) the greenhouse gas that is captured for permanent storage is captured by, or transferred to, a relevant person; and
(b) the amount of the greenhouse gas that is captured for permanent storage is estimated in accordance with section 1.19E; and
(c) the relevant person issues a written certificate that complies with subsection (2).
(2) The certificate must specify:
(a) if the greenhouse gas is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—the following information:
(i) the amount of the greenhouse gas, measured in CO2‑e tonnes, captured by the relevant person;
(ii) the volume of the greenhouse gas stream containing the captured greenhouse gas;
(iii) the concentration of the greenhouse gas in the stream; or
(b) if the greenhouse gas is transferred to the relevant person—the following information:
(i) the amount of the greenhouse gas, measured in CO2‑e tonnes, that was transferred to the relevant person;
(ii) the volume of the greenhouse gas stream containing the transferred greenhouse gas;
(iii) the concentration of the greenhouse gas in the stream.
(3) The amount of the greenhouse gas that may be deducted is the amount specified in the certificate under paragraph (1)(c).
1.19C Capture from facility with multiple sources jointly generated
If, during the operation of a facility, more than 1 source generates a greenhouse gas, the total amount of the greenhouse gas that may be deducted in relation to the facility is to be attributed:
(a) if it is possible to determine the amount of the greenhouse gas that is captured for permanent storage from each source—to each source from which the greenhouse gas is captured according to the amount captured from the source; or
(b) if it is not possible to determine the amount of the greenhouse gas captured for permanent storage from each source—to the main source that generated the greenhouse gas that is captured during the operation of the facility.
1.19D Capture from a source where multiple fuels consumed
If more than 1 fuel is consumed for a source that generates a greenhouse gas that is captured for permanent storage, the total amount of the greenhouse gas that may be deducted in relation to the source is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source.
1.19E Measure of quantity of captured greenhouse gas
(1) For paragraph 1.19B(1)(b), the amount of a greenhouse gas that is captured must be estimated in accordance with this section.
(2) The volume of the greenhouse gas stream containing the captured greenhouse gas must be estimated:
(a) if the greenhouse gas stream is transferred to a relevant person—using:
(i) criterion A in section 1.19F; or
(ii) criterion AAA in section 1.19G; or
(b) if the greenhouse gas stream is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—using:
(i) criterion AAA in section 1.19G; or
(ii) criterion BBB in section 1.19GA.
(3) The greenhouse gas stream must be sampled in accordance with ISO 10715:1997, or an equivalent standard.
(4) The concentration of the greenhouse gas in the greenhouse gas stream must be analysed in accordance with the following parts of ISO 6974 or an equivalent standard:
(a) Part 1 (2000);
(b) Part 2 (2001);
(c) Part 3 (2000);
(d) Part 4 (2000);
(e) Part 5 (2000);
(f) Part 6 (2002).
(5) The volume of the greenhouse gas stream must be expressed in cubic metres.
(6) The greenhouse gas stream must be analysed for the concentration of the greenhouse gas on at least a monthly basis.
1.19F Volume of greenhouse gas stream—criterion A
(1) For subparagraph 1.19E(2)(a)(i), criterion A is the volume of the greenhouse gas stream that is:
(a) transferred to the relevant person during the year; and
(b) specified in a certificate issued by the relevant person under paragraph 1.19B(1)(c).
(2) The volume specified in the certificate must be accurate and must be evidenced by invoices issued by the relevant person.
1.19G Volume of greenhouse gas stream—criterion AAA
(1) For subparagraphs 1.19E(2)(a)(ii) and (b)(i), criterion AAA is the measurement during the year of the captured greenhouse gas stream from the operation of a facility at the point of capture.
(2) In measuring the quantity of the greenhouse gas stream at the point of capture, the quantity of the greenhouse gas stream must be measured:
(a) using volumetric measurement in accordance with:
(i) for a compressed greenhouse gas stream—section 1.19H; and
(ii) for a super‑compressed greenhouse gas stream—section 1.19I; and
(b) using gas measuring equipment that complies with section 1.19J.
(3) The measurement must be carried out using measuring equipment that:
(a) is in a category specified in column 2 of an item in the table in subsection (4) according to the maximum daily quantity of the greenhouse gas stream captured specified in column 3 for that item from the operation of the facility; and
(b) complies with the transmitter and accuracy requirements for that equipment specified in column 4 for that item, if the requirements are applicable to the measuring equipment being used.
(4) For subsection (3), the table is as follows.
| Item | Gas measuring equipment category | Maximum daily quantity of greenhouse gas stream
(cubic metres/day) | Transmitter and accuracy requirements (% of range) |
| 1 | 1 | 0–50 000 | Pressure <±0.25% Diff. pressure <±0.25% Temperature <±0.50% |
| 2 | 2 | 50 001–100 000 | Pressure <±0.25% Diff. pressure <±0.25% Temperature <±0.50% |
| 3 | 3 | 100 001–500 000 | Smart transmitters: Pressure <±0.10% Diff. pressure <±0.10% Temperature <±0.25% |
| 4 | 4 | 500 001 or more | Smart transmitters: Pressure <±0.10% Diff. pressure <±0.10% Temperature <±0.25% |
1.19GA Volume of greenhouse gas stream—criterion BBB
For subparagraph 1.19E(2)(b)(ii), criterion BBB is the estimation of the volume of the captured greenhouse gas stream from the operation of the facility during a year measured in accordance with industry practice, if the equipment used to measure the volume of the captured greenhouse gas stream does not meet the requirements of criterion AAA.
Note: An estimate obtained using industry practice must be considered with the principles in section 1.13.
1.19H Volumetric measurement—compressed greenhouse gas stream
(1) For subparagraph 1.19G(2)(a)(i), volumetric measurement of a compressed greenhouse gas stream must be in cubic metres at standard conditions.
(1A) For this section and subparagraph 1.19G(2)(a)(i), a compressed greenhouse gas stream does not include either of the following:
(a) a super‑compressed greenhouse gas stream;
(b) a greenhouse gas stream that is compressed to a super‑critical state.
(2) The volumetric measurement is to be calculated using a flow computer that measures and analyses flow signals and relative density:
(a) if the greenhouse gas stream is captured by the relevant person and is neither transferred to the relevant person nor transferred by the relevant person to another person—at the point of capture of the greenhouse gas stream; or
(b) if the greenhouse gas stream is transferred to a relevant person—at the point of transfer of the greenhouse gas stream.
(3) The volumetric flow rate must be continuously recorded and integrated using an integration device that is isolated from the flow computer in such a way that if the computer fails, the integration device will retain the last reading, or the previously stored information, that was on the computer immediately before the failure.
(4) Subject to subsection (5), all measurements, calculations and procedures used in determining volume (except for any correction for deviation from the ideal gas law) must be made in accordance with the instructions contained in the following:
(a) for orifice plate measuring systems:
(i) the publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992; or
(ii) Parts 1 to 4 of the publication entitled ANSI/API MPMS Chapter 14.3 Part 2 (R2011) Natural Gas Fluids Measurement: Concentric, Square‑Edged Orifice Meters ‑ Part 2: Specification and Installation Requirements, 4th edition, published by the American Petroleum Institute on 30 April 2000;
(b) for turbine measuring systems—the publication entitled AGA Report No. 7, Measurement of Natural Gas by Turbine Meter (2006), published by the American Gas Association on 1 January 2006;
(c) for positive displacement measuring systems—the publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000.
(5) Measurements, calculations and procedures used in determining volume may also be made in accordance with an equivalent internationally recognised documentary standard or code.
(6) Measurements must comply with Australian legal units of measurement.
1.19I Volumetric measurement—super‑compressed greenhouse gas stream
(1) For subparagraph 1.19G(2)(a)(ii), volumetric measurement of a super‑compressed greenhouse gas stream must be in accordance with this section.
(2) If, in determining volume in relation to the super‑compressed greenhouse gas stream, it is necessary to correct for deviation from the ideal gas law, the correction must be determined using the relevant method contained in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994.
(3) The measuring equipment used must calculate super‑compressibility by:
(a) if the measuring equipment is category 3 or 4 equipment in accordance with column 2 the table in subsection 1.19G(4)—using composition data; or
(b) if the measuring equipment is category 1 or 2 equipment in accordance with column 2 of the table in subsection 1.19G(4)—using an alternative method set out in the publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994.
1.19J Gas measuring equipment—requirements
For paragraph 1.19G(2)(b), gas measuring equipment that is category 3 or 4 equipment in accordance with column 2 of the table in subsection 1.19G(4) must comply with the following requirements:
(a) if the equipment uses flow devices—the requirements relating to flow devices set out in section 1.19K;
(b) if the equipment uses flow computers—the requirement relating to flow computers set out in section 1.19L;
(c) if the equipment uses gas chromatographs—the requirements relating to gas chromatographs set out in section 1.19M.
1.19K Flow devices—requirements
(1) If the measuring equipment has flow devices that use orifice measuring systems, the flow devices must be constructed in a manner that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%.
Note: The publication entitled AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 3: Natural Gas Applications, published by the American Gas Association in August 1992, sets out a manner that ensures that the maximum uncertainty of the discharge coefficient is not greater than ±1.5%.
(2) If the measuring equipment has flow devices that use turbine measuring systems, the flow devices must be installed in a manner that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%.
Note: The publication entitled AGA Report No. 8, Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994), published by the American Gas Association on 1 January 1994, sets out a manner that ensures that the maximum uncertainty of the flow measurement is not greater than ±1.5%.
(3) If the measuring equipment has flow devices that use positive displacement measuring systems, the flow devices must be installed in a manner that ensures that the maximum uncertainty of flow is ±1.5%.
Note: The publication entitled ANSI B109.3—2000, Rotary Type Gas Displacement Meters, published by the American Gas Association on 13 April 2000, sets out a manner for installation that ensures that the maximum uncertainty of flow is ±1.5%.
(4) If the measuring equipment uses any other type of flow device, the maximum uncertainty of flow measurement must not be greater than ±1.5%.
(5) All flow devices that are used by measuring equipment of a category specified in column 2 of the table in subsection 1.19G(4) must, wherever possible, be calibrated for pressure, differential pressure and temperature in accordance with the requirements specified in column 4 for the category of equipment specified in column 2 for that item. The calibrations must take into account the effects of static pressure and ambient temperature.
1.19L Flow computers—requirements
For paragraph 1.19J(b), the requirement is that the flow computer that is used by the equipment for measuring purposes must record the instantaneous values for all primary measurement inputs and must also record the following outputs:
(a) instantaneous corrected volumetric flow;
(b) cumulative corrected volumetric flow;
(c) for turbine and positive displacement metering systems—instantaneous uncorrected volumetric flow;
(d) for turbine and positive displacement metering systems—cumulative uncorrected volumetric flow;
(e) super‑compressibility factor.
1.19M Gas chromatographs
For paragraph 1.19J(c), the requirements are that gas chromatographs used by the measuring equipment must:
(a) be factory tested and calibrated using a measurement standard produced by gravimetric methods and traceable to Australian legal units of measurement; and
(b) perform gas composition analysis with an accuracy of ±0.25% for calculation of relative density; and
(c) include a mechanism for re‑calibration against a certified reference gas.
Part 1.3—Method 4—Direct measurement of emissions
Division 1.3.1—Preliminary
1.20 Overview
(1) This Chapter provides for method 4 for a source.
Note: Method 4 as provided for in this Part applies to a source as indicated in the Chapter, Part, Division or Subdivision dealing with the source.
(2) Method 4 requires the direct measurement of emissions released from the source from the operation of a facility during a year by monitoring the gas stream at a site within part of the area (for example, a duct or stack) occupied for the operation of the facility.
(3) Method 4 consists of the following:
(a) method 4 (CEM) as specified in section 1.21 that requires the measurement of emissions using continuous emissions monitoring (CEM);
(b) method 4 (PEM) as specified in section 1.27 that requires the measurement of emissions using periodic emissions monitoring (PEM).
Division 1.3.2—Operation of method 4 (CEM)
Subdivision 1.3.2.1—Method 4 (CEM)
1.21 Method 4 (CEM)—estimation of emissions
(1) To obtain an estimate of the mass of emissions of a gas type (j), being methane, carbon dioxide or nitrous oxide, released at the time of measurement at a monitoring site within the area occupied for the operation of a facility, the following formula must be applied:
where:
Mjct is the mass of emissions in tonnes of gas type (j) released per second.
MMj is the molecular mass of gas type (j) measured in tonnes per kilomole which:
(a) for methane is 16.04
10‑3; or
(b) for carbon dioxide is 44.0110‑3; or
(c) for nitrous oxide is 44.0110‑3.
Pct is the pressure of the gas stream in kilopascals at the time of measurement.
FRct is the flow rate of the gas stream in cubic metres per second at the time of measurement.
Cjct is the proportion of gas type (j) in the volume of the gas stream at the time of measurement.
Tct is the temperature, in degrees kelvin, of the gas at the time of measurement.
(2) The mass of emissions estimated under subsection (1) must be converted into CO2‑e tonnes.
(3) Data on estimates of the mass emissions rates obtained under subsection (1) during an hour must be converted into a representative and unbiased estimate of mass emissions for that hour.
(4) The estimate of emissions of gas type (j) during a year is the sum of the estimates for each hour of the year worked out under subsection (3).
(5) If method 1 is available for the source, the total mass of emissions for a gas from the source for the year calculated under this section must be reconciled against an estimate for that gas from the facility for the same period calculated using method 1 for that source.
1.21A Emissions from a source where multiple fuels consumed
If more than one fuel is consumed for a source that generates carbon dioxide that is directly measured using method 4 (CEM), the total amount of carbon dioxide is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source.
Subdivision 1.3.2.2—Method 4 (CEM)—use of equipment
1.22 Overview
The following apply to the use of equipment for CEM:
(a) the requirements in section 1.23 about location of the sampling positions for the CEM equipment;
(b) the requirements in section 1.24 about measurement of volumetric flow rates in the gas stream;
(c) the requirements in section 1.25 about measurement of the concentrations of greenhouse gas in the gas stream;
(d) the requirements in section 1.26 about frequency of measurement.
1.23 Selection of sampling positions for CEM equipment
For paragraph 1.22(a), the location of sampling positions for the CEM equipment in relation to the gas stream must be selected in accordance with an appropriate standard.
Note: Appropriate standards include:
· AS 4323.1—1995 Stationary source emissions ‑ Selection of sampling positions.
· AS 4323[1].1—1995 Amdt 1‑1995 Stationary source emissions ‑ Selection of sampling positions.
· ISO 10396:2007 Stationary source emissions ‑ Sampling for the automated determination of gas emission concentrations for permanently‑installed monitoring systems.
· ISO 10012:2003 Measurement management systems ‑ Requirements for measurement processes and measuring equipment.
· USEPA – Method 1 – Sample and Velocity Traverses for Stationary Sources (2000).
1.24 Measurement of flow rates by CEM
For paragraph 1.22(b), the measurement of the volumetric flow rates by CEM of the gas stream must be undertaken in accordance with an appropriate standard.
Note: Appropriate standards include:
· ISO 10780:1994 Stationary source emissions—Measurement of velocity and volume flowrate of gas streams in ducts.
· ISO 14164:1999 Stationary source emissions—Determination of the volume flowrate of gas streams in ducts ‑ Automated method.
· USEPA Method 2 Determination of Stack Gas Velocity and Volumetric flowrate (Type S Pitot tube) (2000).
· USEPA Method 2A Direct Measurement of Gas Volume Through Pipes and Small Ducts (2000).
1.25 Measurement of gas concentrations by CEM
For paragraph 1.22(c), the measurement of the concentrations of gas in the gas stream by CEM must be undertaken in accordance with an appropriate standard.
Note: Appropriate standards include:
· USEPA Method 3A Determination of oxygen and carbon dioxide concentrations in emissions from stationary sources (instrumental analyzer procedure) (2006).
· USEPA Method 3C Determination of carbon dioxide, methane, nitrogen, and oxygen from stationary sources (1996).
· ISO 12039:2001 Stationary source emissions—Determination of carbon monoxide, carbon dioxide and oxygen—Performance characteristics and calibration of automated measuring system.
1.26 Frequency of measurement by CEM
(1) For paragraph 1.22(d), measurements by CEM must be taken frequently enough to produce data that is representative and unbiased.
(2) For subsection (1), if part of the CEM equipment is not operating for a period, readings taken during periods when the equipment was operating may be used to estimate data on a pro rata basis for the period that the equipment was not operating.
(3) Frequency of measurement will also be affected by the nature of the equipment.
Example: If the equipment is designed to measure only one substance, for example, carbon dioxide or methane, measurements might be made every minute. However, if the equipment is designed to measure different substances in alternate time periods, measurements might be made much less frequently, for example, every 15 minutes.
(4) The CEM equipment must operate for more than 90% of the period for which it is used to monitor an emission.
(5) In working out the period during which CEM equipment is being used to monitor for the purposes of subsection (4), exclude downtime taken for the calibration of equipment.
Division 1.3.3—Operation of method 4 (PEM)
Subdivision 1.3.3.1—Method 4 (PEM)
1.27 Method 4 (PEM)—estimation of emissions
(1) To obtain an estimate of the mass emissions rate of methane, carbon dioxide or nitrous oxide released at the time of measurement at a monitoring site within the area occupied for the operation of a facility, the formula in subsection 1.21(1) must be applied.
(2) The mass of emissions estimated under the formula must be converted into CO2‑e tonnes.
(3) The average mass emissions rate for the gas measured in CO2‑e tonnes per hour for a year must be calculated from the estimates obtained under subsection (1).
(4) The total mass of emissions of the gas for the year is calculated by multiplying the average emissions rate obtained under subsection (3) by the number of hours during the year when the site was operating.
(5) If method 1 is available for the source, the total mass of emissions of the gas for a year calculated under this section must be reconciled against an estimate for that gas from the site for the same period calculated using method 1 for that source.
1.27A Emissions from a source where multiple fuels consumed
If more than one fuel is consumed for a source that generates carbon dioxide that is directly measured using method 4 (PEM), the total amount of carbon dioxide is to be attributed to each fuel consumed in proportion to the carbon content of the fuel relative to the total carbon content of all fuel consumed for that source.
1.28 Calculation of emission factors
(1) Data obtained from periodic emissions monitoring of a gas stream may be used to estimate the average emission factor for the gas per unit of fuel consumed or material produced.
(2) In this section, data means data about:
(a) volumetric flow rates estimated in accordance with section 1.31; or
(b) gas concentrations estimated in accordance with section 1.32; or
(c) consumption of fuel or material input, estimated in accordance with Chapters 2 to 7; or
(d) material produced, estimated in accordance with Chapters 2 to 7.
Subdivision 1.3.3.2—Method 4 (PEM)—use of equipment
1.29 Overview
The following requirements apply to the use of equipment for PEM:
(a) the requirements in section 1.30 about location of the sampling positions for the PEM equipment;
(b) the requirements in section 1.31 about measurement of volumetric flow rates in a gas stream;
(c) the requirements in section 1.32 about measurement of the concentrations of greenhouse gas in the gas stream;
(d) the requirements in section 1.33 about representative data.
1.30 Selection of sampling positions for PEM equipment
For paragraph 1.29(a), the location of sampling positions for PEM equipment must be selected in accordance with an appropriate standard.
Note: Appropriate standards include:
· AS 4323.1—1995 Stationary source emissions—Selection of sampling positions.
· AS 4323.1‑1995 Amdt 1‑1995 Stationary source emissions—Selection of sampling positions.
· ISO 10396:2007 Stationary source emissions—Sampling for the automated determination of gas emission concentrations for permanently‑installed monitoring systems.
· ISO 10012:2003 Measurement management systems—Requirements for measurement processes and measuring equipment.
· USEPA Method 1 Sample and Velocity Traverses for Stationary Sources (2000).
1.31 Measurement of flow rates by PEM equipment
For paragraph 1.29(b), the measurement of the volumetric flow rates by PEM of the gas stream must be undertaken in accordance with an appropriate standard.
Note: Appropriate standards include:
· ISO 10780:1994 Stationary source emissions – Measurement of velocity and volume flowrate of gas streams in ducts.
· ISO 14164:1999 Stationary source emissions. Determination of the volume flow rate of gas streams in ducts – automated method.
· USEPA Method 2 Determination of stack velocity and volumetric flow rate (Type S Pitot tube) (2000).
· USEPA Method 2A Direct measurement of gas volume through pipes and small ducts (2000).
1.32 Measurement of gas concentrations by PEM
For paragraph 1.29(c), the measurement of the concentrations of greenhouse gas in the gas stream by PEM must be undertaken in accordance with an appropriate standard.
Note: Appropriate standards include:
· USEPA Method 3A Determination of oxygen and carbon dioxide concentrations in emissions from stationary sources (instrumental analyser procedure) (2006).
· USEPA Method 3C Determination of carbon dioxide, methane, nitrogen, and oxygen from stationary sources (1996).
· ISO12039:2001 Stationary source emissions – Determination of carbon monoxide, carbon dioxide and oxygen – Performance characteristics and calibration of an automated measuring method.
1.33 Representative data for PEM
(1) For paragraph 1.29(d), sampling by PEM must be undertaken during the year for a sufficient duration to produce representative data that may be reliably extrapolated to provide estimates of emissions across the full range of operating conditions for that year.
(2) Emission estimates using PEM equipment must also be consistent with the principles in section 1.13.
Division 1.3.4—Performance characteristics of equipment
1.34 Performance characteristics of CEM or PEM equipment
(1) The performance characteristics of CEM or PEM equipment must be measured in accordance with this section.
(2) The test procedure specified in an appropriate standard must be used for measuring the performance characteristics of CEM or PEM equipment.
(3) For the calibration of CEM or PEM equipment, the test procedure must be:
(a) undertaken by an accredited laboratory; or
(b) undertaken by a laboratory that meets requirements equivalent to ISO 17025; or
(c) undertaken in accordance with applicable State or Territory legislation.
(4) As a minimum requirement, a cylinder of calibration gas must be certified by an accredited laboratory accredited to ISO Guide 34:2000 as being within 2% of the concentration specified on the cylinder label.
Chapter 2—Fuel combustion
Part 2.1—Preliminary
2.1 Outline of Chapter
This Chapter provides for the following matters:
(a) emissions released from the following sources:
(i) the combustion of solid fuels (see Part 2.2);
(ii) the combustion of gaseous fuels (Part 2.3);
(iii) the combustion of liquid fuels (Part 2.4);
(iv) fuel use by certain industries (Part 2.5);
(b) the measurement of fuels in blended fuels (Part 2.6);
(c) the estimation of energy for certain purposes (Part 2.7).
Part 2.2—Emissions released from the combustion of solid fuels
Division 2.2.1—Preliminary
2.2 Application
This Part applies to emissions released from the combustion of solid fuel in relation to a separate instance of a source if the amount of solid fuel combusted in relation to the separate instance of the source is more than 1 tonne.
2.3 Available methods for estimating emissions of carbon dioxide, methane and nitrous oxide
(1) Subject to section 1.18, for estimating emissions released from the combustion of a solid fuel consumed from the operation of a facility during a year:
(a) one of the following methods must be used for estimating emissions of carbon dioxide:
(i) subject to subsection (3), method 1 under section 2.4;
(ii) method 2 using an oxidation factor under section 2.5 or an estimated oxidation factor under section 2.6;
(iii) method 3 using an oxidation factor or an estimated oxidation factor under section 2.12;
(iv) method 4 under Part 1.3; and
(b) method 1 under section 2.4 must be used for estimating emissions of methane and nitrous oxide.
(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
(3) Method 1 must not be used for estimating emissions of carbon dioxide for the main fuel combusted from the operation of the facility if:
(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611); and
(b) the generating unit:
(i) has the capacity to produce 30 megawatts or more of electricity; and
(ii) generates more than 50 000 megawatt hours of electricity in a reporting year.
Note: There is no method 2, 3 or 4 for paragraph (1)(b).
Division 2.2.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide from solid fuels
2.4 Method 1—solid fuels
For subparagraph 2.3(1)(a)(i), method 1 is:
where:
Eij is the emissions of gas type (j), being carbon dioxide, methane or nitrous oxide, released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2‑e tonnes.
Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5.
ECi is the energy content factor of fuel type (i) estimated under section 6.5.
EFijoxec is the emission factor for each gas type (j) (which includes the effect of an oxidation factor) released from the combustion of fuel type (i) measured in kilograms of CO2‑e per gigajoule according to source as mentioned in Schedule 1.
Division 2.2.3—Method 2—emissions from solid fuels
Subdivision 2.2.3.1—Method 2—estimating carbon dioxide using default oxidation factor
2.5 Method 2—estimating carbon dioxide using oxidation factor
(1) For subparagraph 2.3(1)(a)(ii), method 2 is:
where:
Eico2 means the emissions of carbon dioxide released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2‑e tonnes.
Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5.
ECi is the energy content factor of fuel type (i) estimated under section 6.5.
EFico2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2‑e per gigajoule:
(a) if the fuel’s emissions factor for carbon dioxide is 0 in Schedule 1—deemed to be 0 kilograms of CO2‑e per gigajoule; or
(a) otherwise—as worked out under subsection (2).
γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes.
RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.
(2) For EFico2oxec in subsection (1), estimate as follows:
where:
EFico2ox,kg is the carbon dioxide emission factor for fuel type (i) measured in kilograms of CO2‑e per kilogram of fuel as worked out under subsection (3).
ECi is the energy content factor of fuel type (i) as obtained under subsection (1).
(3) For EFico2ox,kg in subsection (2), work out as follows:
where:
Car is the percentage of carbon in fuel type (i), as received for the facility or as combusted from the operation of the facility, worked out under subsection (4).
OFs, or oxidation factor, is 1.0.
(4) For Car in subsection (3), work out as follows:
where:
Cdaf is the amount of carbon in fuel type (i) as a percentage of the dry ash‑free mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.
Mar is the amount of moisture in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.
Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.
Subdivision 2.2.3.2—Method 2—estimating carbon dioxide using an estimated oxidation factor
2.6 Method 2—estimating carbon dioxide using an estimated oxidation factor
(1) For subparagraph 2.3(1)(a)(ii), method 2 is:
where:
Eico2 means the emissions of carbon dioxide released from the combustion of fuel type (i) from the operation of the facility during the year measured in CO2‑e tonnes.
Qi is the quantity of fuel type (i) measured in tonnes and estimated under Division 2.2.5.
ECi is the energy content factor of fuel type (i) estimated under section 6.5.
EFico2oxec is:
(a) if the fuel’s emissions factor for carbon dioxide is 0 in Schedule 1—deemed to be 0 kilograms CO2‑e per gigajoule;
(b) otherwise—the amount worked out under subsection (2).
γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes.
RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.
(2) For EFico2oxec in subsection (1), work out as follows:
where:
EFico2ox,kg is the carbon dioxide emission factor for the type of fuel measured in kilograms of CO2‑e per kilogram of the type of fuel as worked out under subsection (3).
ECi is the energy content factor of fuel type (i) as obtained under subsection (1).
(3) For EFico2ox,kg in subsection (2), estimate as follows:
where:
Car is the percentage of carbon in fuel type (i), as received for the facility or as combusted from the operation of the facility, worked out under subsection (4).
Ca is the amount of carbon in the ash estimated as a percentage of the as‑sampled mass that is the weighted average of fly ash and ash by sampling and analysis in accordance with Subdivision 2.2.3.3.
Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.
(4) For Car, in subsection (3), estimate as follows:
where:
Cdaf is the amount of carbon in fuel type (i) as a percentage of the dry ash‑free mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.
Mar is the amount of moisture in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.
Aar is the amount of ash in fuel type (i) as a percentage of the as received or as combusted mass of the fuel estimated using the sampling and analysis provided for in Subdivision 2.2.3.3.
Subdivision 2.2.3.3—Sampling and analysis for method 2 under sections 2.5 and 2.6
2.7 General requirements for sampling solid fuels
(1) A sample of the solid fuel must be derived from a composite of amounts of the solid fuel combusted.
(2) The samples must be collected on enough occasions to produce a representative sample.
(3) The samples must also be free of bias so that any estimates are neither over nor under estimates of the true value.
(4) Bias must be tested in accordance with an appropriate standard (if any).
Note: An appropriate standard for most solid mineral fuels is AS 4264.4—1996 Coal and coke—Sampling—Determination of precision and bias.
(5) The value obtained from the sample must only be used for the delivery period or consignment of the fuel for which it was intended to be representative.
2.8 General requirements for analysis of solid fuels
(1) A standard for analysis of a parameter of a solid fuel, and the minimum frequency of analysis of a solid fuel, is as set out in Schedule 2.
(2) A parameter of a solid fuel may also be analysed in accordance with a standard that is equivalent to a standard set out in Schedule 2.
(3) Analysis must be undertaken by an accredited laboratory that meets the requirements equivalent to those in AS ISO/IEC 17025:2005. However, analysis may be undertaken by an on‑line analyser if:
(a) the analyser is calibrated in accordance with an appropriate standard; and
(b) analysis undertaken to meet the standard is done by a laboratory that meets the requirements equivalent to those in AS ISO/IEC 17025:2005.
Note: An appropriate standard is AS 1038.24—1998, Coal and coke—Analysis and testing, Part 24: Guide to the evaluation of measurements made by on‑line coal analysers.
(4) If a delivery of fuel lasts for a month or less, analysis must be conducted on a delivery basis.
(5) However, if the properties of the fuel do not change significantly between deliveries over a period of a month, analysis may be conducted on a monthly basis.
(6) If a delivery of fuel lasts for more than a month, and the properties of the fuel do not change significantly before the next delivery, analysis of the fuel may be conducted on a delivery basis rather than monthly basis.
2.9 Requirements for analysis of furnace ash and fly ash
For furnace ash and fly ash, analysis of the carbon content must be undertaken in accordance with AS 3583.2—1991 Determination of moisture content and AS 3583.3—1991 Determination of loss on ignition or a standard that is equivalent to those standards.
2.10 Requirements for sampling for carbon in furnace ash
(1) This section applies to furnace ash sampled for its carbon content if the ash is produced from the operation of a facility that is constituted by a plant.
(2) A sample of the ash must be derived from representative operating conditions in the plant.
(3) A sample of ash may be collected:
(a) if contained in a wet extraction system—by using sampling ladles to collect it from sluiceways; or
(b) if contained in a dry extraction system—directly from the conveyer; or
(c) if it is not feasible to use one of the collection methods mentioned in paragraph (a) or (b)—by using another collection method that provides representative ash sampling.
2.11 Sampling for carbon in fly ash
Fly ash must be sampled for its carbon content in accordance with:
(a) a procedure set out in column 2 of an item in the following table, and at a frequency set out in column 3 for that item; or
(b) if it is not feasible to use one of the procedures mentioned in paragraph (a)—another procedure that provides representative ash sampling, at least every two years, or after significant changes in operating conditions.
| Item | Procedure | Frequency |
| 1 | At the outlet of a boiler air heater or the inlet to a flue gas cleaning plant using the isokinetic sampling method in AS 4323.1—1995 or AS 4323.2—1995, or in a standard that is equivalent to one of those standards | At least every 2 years, or after significant changes in operating conditions |
| 2 | By using standard industry ‘cegrit’ extraction equipment | At least every year, or after significant changes in operating conditions |
| 3 | By collecting fly ash from: (a) the fly ash collection hoppers of a flue gas cleaning plant; or (b) downstream of fly ash collection hoppers from ash silos or sluiceways | At least once a year, or after significant changes in operating conditions |
| 4 | From on‑line carbon in ash analysers using sample extraction probes and infrared analysers | At least every 2 years, or after significant changes in operating conditions |
Division 2.2.4—Method 3—Solid fuels
2.12 Method 3—solid fuels using oxidation factor or an estimated oxidation factor
(1) For subparagraph 2.3(1)(a)(iii) and subject to this section, method 3 is the same as method 2 whether using the oxidation factor under section 2.5 or using an estimated oxidation factor under section 2.6.
(2) In applying method 2 as mentioned in subsection (1), solid fuels must be sampled in accordance with the appropriate standard mentioned in the table in subsection (3).
(3) A standard for sampling a solid fuel mentioned in column 2 of an item in the following table is as set out in column 3 for that item:
| Item | Fuel | Standard |
| 1 | Bituminous coal | AS 4264.1—2009 |
| 1A | Sub‑bituminous coal | AS 4264.1—2009 |
| 1B | Anthracite | AS 4264.1—2009 |
| 2 | Brown coal | AS 4264.3—1996 |
| 3 | Coking coal (metallurgical coal) | AS 4264.1—2009 |
| 4 | Coal briquettes | AS 4264.3—1996 |
| 5 | Coal coke | AS 4264.2—1996 |
| 6 | Coal tar | |
| 7 | Industrial materials that are derived from fossil fuels, if recycled and combusted to produce heat or electricity | CEN/TS 14778 – 1:2006 CEN/TS 15442:2006 |
| 7A | Passenger car tyres, if recycled and combusted to produce heat or electricity | CEN/TS 14778 – 1:2006 CEN/TS 15442:2006 |
| 7B | Truck and off-road tyres, if recycled and combusted to produce heat or electricity | CEN/TS 14778 – 1:2006 CEN/TS 15442:2006 |
| 8 | Non‑biomass municipal materials, if recycled and combusted to produce heat or electricity | CEN/TS 14778 – 1:2005 CEN/TS 15442:2006 |
| 9 | Dry wood | CEN/TS 14778 – 1:2005 CEN/TS 15442:2006 |
| 10 | Green and air dried wood | CEN/TS 14778 – 1:2005 CEN/TS 15442:2006 |
| 11 | Sulphite lyes | CEN/TS 14778 – 1:2005 CEN/TS 15442:2006 |
| 12 | Bagasse | CEN/TS 14778 – 1:2005 CEN/TS 15442:2006 |
| 13 | Primary solid biomass other than items 9 to 12 and 14 to 15 | CEN/TS 14778 – 1:2005 CEN/TS 15442:2006 |
| 14 | Charcoal | CEN/TS 14778 – 1:2005 CEN/TS 15442:2006 |
| 15 | Biomass municipal and industrial materials, if recycled and combusted to produce heat or electricity | CEN/TS 14778 – 1:2005 CEN/TS 15442:2006 |
(4) A solid fuel may also be sampled in accordance with a standard that is equivalent to a standard set out in the table in subsection (3).
Note: The analysis is carried out in accordance with the same requirements as for method 2.
Division 2.2.5—Measurement of consumption of solid fuels
2.13 Purpose of Division
This Division sets out how quantities of solid fuels combusted from the operation of a facility are to be estimated for the purpose of working out the emissions released from the combustion of that fuel.
2.14 Criteria for measurement
(1) For the purpose of calculating the amount of solid fuel combusted from the operation of a facility during a year and, in particular, for Qi in sections 2.4, 2.5 and 2.6, the quantity of combustion must be estimated in accordance with this section.
Acquisition involves commercial transaction
(2) If the acquisition of the solid fuel involves a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:
(a) the amount of the solid fuel delivered for the facility during the year as evidenced by invoices issued by the vendor of the fuel (criterion A);
(b) as provided in section 2.15 (criterion AA);
(c) as provided in section 2.16 (criterion AAA).
(3) If, during a year, criterion AA, or criterion AAA using paragraph 2.16(2)(a), is used to estimate the quantity of fuel combusted, then, in each year following that year, only criterion AA, or criterion AAA using paragraph 2.16(2)(a), (respectively) is to be used.
Acquisition does not involve commercial transaction
(4) If the acquisition of the solid fuel does not involve a commercial transaction, the quantity of fuel combusted must be estimated using one of the following criteria:
(a) as provided in paragraph 2.16(2)(a) (criterion AAA);
(b) as provided in section 2.17 (criterion BBB).
2.15 Indirect measurement at point of consumption—criterion AA
(1) For paragraph 2.14(2)(b), criterion AA is the amount of the solid fuel combusted from the operation of the facility during a year based on amounts delivered for the facility during the year as adjusted for the estimated change in the quantity of the stockpile of the fuel for the facility during the year.
(2) To work out the adjustment for the estimated change in the quantity of the stockpile of the fuel for the facility during the year, one of the following approaches must be used:
(a) the survey approach mentioned in subsection (2C);
(b) the error allowance approach mentioned in subsection (2D).
(2A) The approach selected must be consistent with the principles mentioned in section 1.13.
(2B) The same approach, once selected, must be used for the facility for each year unless:
(a) there has been a material change in the management of the stockpile during the year; and
(b) the change in the management of the stockpile results in the approach selected being less accurate than the alternative approach.
(2C) The survey approach is as follows:
Step 1. Estimate the quantity of solid fuel in the stockpile by:
(a) working out the volume of the solid fuel in the stockpile using aerial or general survey in accordance with industry practice; and
(b) measuring the bulk density of the stockpile in accordance with subregulation (3).
Step 2. Replace the current book quantity with the quantity estimated under step 1.
Step 3. Maintain the book quantity replaced under step 2 by:
(a) adding deliveries made during the year, using:
(i) invoices received for solid fuel delivered to the facility; or
(ii) solid fuel sampling and measurements provided by measuring equipment calibrated to a measurement requirement; and
(b) deducting from the amount calculated under paragraph (a), solid fuel consumed by the facility.
Step 4. Use the book quantity maintained under step 3 to estimate the change in the quantity of the stockpile of the fuel.
(2D) The error allowance approach is as follows:
Step 1. Estimate the quantity of the stockpile by:
(a) working out the volume of the solid fuel in the stockpile using aerial or general survey in accordance with industry practice; and
(b) measuring the bulk density of the stockpile in accordance with subregulation (3).
Step 2. Estimate an error tolerance for the quantity of solid fuel in the stockpile. The error tolerance is an estimate of the uncertainty of the quantity of solid fuel in the stockpile and must be:
(a) based on stockpile management practices at the facility and the uncertainty associated with the energy content and proportion of carbon in the solid fuel; and
(b) consistent with the general principles in section 1.13; and
(c) not more than 6% of the estimated value of the solid fuel in the stockpile worked out under step 1.
Step 3. Work out the percentage difference between the current book quantity and the quantity of solid fuel in the stockpile estimated under step 1.
Step 4. If the percentage difference worked out under step 3 is within the error tolerance worked out under step 2, use the book quantity to estimate the change in the quantity of the stockpile of the fuel.
Step 5. If the percentage difference worked out in step 3 is more than the error tolerance worked out in step 2:
(a) adjust the book quantity by the difference between the percentage worked out under step 3 and the error tolerance worked out under step 2; and
(b) use the book quantity adjusted under paragraph (a) to estimate the change in the quantity of the stockpile of the fuel.
(3) The bulk density of the stockpile must be measured in accordance with:
(a) the procedure in ASTM D/6347/D 6347M‑99; or
(b) the following procedure:
Step 1 If the mass of the stockpile:
(a) does not exceed 10% of the annual solid fuel combustion from the operation of a facility—extract a sample from the stockpile using a mechanical auger in accordance with ASTM D 4916‑89; or
(b) exceeds 10% of the annual solid fuel combustion — extract a sample from the stockpile by coring.
Step 2 Weigh the mass of the sample extracted.
Step 3 Measure the volume of the hole from which the sample has been extracted.
Step 4 Divide the mass obtained in step 2 by the volume measured in step 3.
(4) Quantities of solid fuel delivered for the facility must be evidenced by invoices issued by the vendor of the fuel.
(5) In this section:
book quantity means the quantity recorded and maintained by the facility operator as the quantity of solid fuel in the stockpile.
2.16 Direct measurement at point of consumption—criterion AAA
(1) For paragraph 2.14(2)(c), criterion AAA is the measurement during a year of the solid fuel combusted from the operation of the facility.
(2) The measurement must be carried out either:
(a) at the point of combustion using measuring equipment calibrated to a measurement requirement; or
(b) at the point of sale using measuring equipment calibrated to a measurement requirement.
(3) Paragraph (2)(b) only applies if:
(a) the change in the stockpile of the fuel for the facility for the year is less than 1% of total combustion on average for the facility during the year; and
(b) the stockpile of the fuel for the facility at the beginning of the year is less than 5% of total combustion for the year.
2.17 Simplified consumption measurements—criterion BBB
For paragraph 2.14(d), criterion BBB is the estimation of the solid fuel combusted during a year from the operation of the facility in accordance with industry practice if the equipment used to measure combustion of the fuel is not calibrated to a measurement requirement.
Note: An estimate obtained using industry practice must be consistent with the principles in section 1.13.
Part 2.3—Emissions released from the combustion of gaseous fuels
Division 2.3.1—Preliminary
2.18 Application
This Part applies to emissions released from the combustion of gaseous fuels in relation to a separate instance of a source if the amount of gaseous fuel combusted in relation to the separate instance of the source is more than 1000 cubic metres.
2.19 Available methods
(1) Subject to section 1.18, for estimating emissions released from the combustion of a gaseous fuel consumed from the operation of a facility during a year:
(a) one of the following methods must be used for estimating emissions of carbon dioxide:
(i) method 1 under section 2.20;
(ii) method 2 under section 2.21;
(iii) method 3 under section 2.26;
(iv) method 4 under Part 1.3; and
(b) one of the following methods must be used for estimating emissions of methane:
(i) method 1 under section 2.20;
(ii) method 2 under section 2.27; and
(c) method 1 under section 2.20 must be used for estimating emissions of nitrous oxide.
Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide. Method 1 is used to estimate emissions of each of these gases. There is no method 3 or 4 for emissions of methane and no method 2, 3 or 4 for emissions of nitrous oxide.
(2) However, for incidental emissions another method may be used that is consistent with the principles in section 1.13.
(3) Method 1 must not be used for estimating emissions of carbon dioxide for the main fuel combusted from the operation of the facility if:
(a) the principal activity of the facility is electricity generation (ANZSIC industry classification and code 2611); and
(b) the generating unit:
(i) has the capacity to produce 30 megawatts or more of electricity; and
(ii) generates more than 50 000 megawatt hours of electricity in a reporting year.
Division 2.3.2—Method 1—emissions of carbon dioxide, methane and nitrous oxide
2.20 Method 1—emissions of carbon dioxide, methane and nitrous oxide
(1) For subparagraphs 2.19(1)(a)(i) and (b)(i) and paragraph 2.19(1)(c), method 1 for estimating emissions of carbon dioxide, methane and nitrous oxide is:
where:
Eij is the emissions of gas type (j), being carbon dioxide, methane or nitrous oxide, from each gaseous fuel type (i) released from the operation of the facility during the year measured in CO2‑e tonnes.
Qi is the quantity of fuel type (i) combusted, whether for stationary energy purposes or transport energy purposes, from the operation of the facility during the year measured in cubic metres or gigajoules and estimated under Division 2.3.6.
ECi is the energy content factor of fuel type (i) estimated under section 6.5.
EFijoxec is the emission factor for each gas type (j) released during the year (which includes the effect of an oxidation factor) measured in kilograms CO2‑e per gigajoule of fuel type (i) according to source as mentioned in:
(a) for stationary energy purposes—Part 2 of Schedule 1; and
(b) for transport energy purposes—Division 4.1 of Schedule 1.
Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide.
(2) In this section:
stationary energy purposes means purposes for which fuel is combusted that do not involve transport energy purposes.
transport energy purposes includes purposes for which fuel is combusted that consist of any of the following:
(a) transport by vehicles registered for road use;
(b) rail transport;
(c) waterborne transport;
(d) air transport.
Note: The combustion of gaseous fuels releases emissions of carbon dioxide, methane and nitrous oxide.
Division 2.3.3—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels
Subdivision 2.3.3.1—Method 2—emissions of carbon dioxide from the combustion of gaseous fuels
2.21 Method 2—emissions of carbon dioxide from the combustion of gaseous fuels
(1) For subparagraph 2.19(1)(a)(ii), method 2 for estimating emissions of carbon dioxide is:
where:
EiCO2 is emissions of carbon dioxide released from fuel type (i) combusted from the operation of the facility during the year measured in CO2‑e tonnes.
Qi is the quantity of fuel type (i) combusted from the operation of the facility during the year measured in cubic metres or gigajoules and estimated under Division 2.3.6.
ECi is the energy content factor of fuel type (i) estimated under section 6.5.
EFiCO2oxec is the carbon dioxide emission factor for fuel type (i) measured in kilograms CO2‑e per gigajoule:
(a) if the fuel’s emissions factor for carbon dioxide is 0 in Schedule 1—deemed to be 0 kilograms CO2‑e per gigajoule;
(b) otherwise—calculated in accordance with section 2.22.
γ is the factor 1.861 × 10‑3 for converting a quantity of carbon dioxide from cubic metres at standard conditions of pressure and temperature to CO2‑e tonnes.
RCCSCO2 is carbon dioxide captured for permanent storage measured in cubic metres in accordance with Division 1.2.3.
2.22 Calculation of emission factors from combustion of gaseous fuel
(1) For section 2.21, the emission factor EFiCO2oxec from the combustion of fuel type (i) must be calculated from information on the composition of each component gas type (y) and must first estimate EFi,CO2,ox,kg in accordance with the following formula:
where:
EFi,CO2,ox,kg is the carbon dioxide emission factor for fuel type (i), incorporating the effects of a default oxidation factor expressed as kilograms of carbon dioxide per kilogram of fuel.
moly%, for each component gas type (y), is that gas type’s share of 1 mole of fuel type (i), or that gas type’s share of the total volume of fuel type (i), expressed as a percentage.
mwy, for each component gas type (y), is the molecular weight of the component gas type (y) measured in kilograms per kilomole.
V is the volume of 1 kilomole of the gas at standard conditions and equal to 23.6444 cubic metres.
dy, total is as set out in subsection (2).
fy for each component gas type (y), is the number of carbon atoms in a molecule of the component gas type (y).
OFg is the oxidation factor 1.0 applicable to gaseous fuels.
(2) For subsection (1), the factor dy, total is worked out using the following formula:
where:
moly%, for each component gas type (y), is that gas type’s share of 1 mole of fuel type (i), or that gas type’s share of the total volume of fuel type (i), expressed as a percentage.
mwy, for each component gas type (y), is the molecular weight of the component gas type (y) measured in kilograms per kilomole.
(3) For subsection (1), the molecular weight and number of carbon atoms in a molecule of each component gas type (y) mentioned in column 2 of an item in the following table is as set out in columns 3 and 4, respectively, for the item:
| Item | Component gas y | Molecular Wt (kg/kmole) | Number of carbon atoms in component molecules |
| 1 | Methane | 16.043 | 1 |
| 2 | Ethane | 30.070 | 2 |
| 3 | Propane | 44.097 | 3 |
| 4 | Butane | 58.123 | 4 |
| 5 | Pentane | 72.150 | 5 |
| 6 | Carbon monoxide | 28.016 | 1 |
| 7 | Hydrogen | 2.016 | 0 |
| 8 | Hydrogen sulphide | 34.082 | 0 |
| 9 | Oxygen | 31.999 | 0 |
| 10 | Water | 18.015 | 0 |
| 11 | Nitrogen | 28.013 | 0 |
| 12 | Argon | 39.948 | 0 |
| 13 | Carbon dioxide | 44.010 | 1 |
(4) The carbon dioxide emission factor EFiCO2oxec derived from the calculation in subsection (1) must be expressed in terms of kilograms of carbon dioxide per gigajoule calculated using the following formula:
where:
ECi is the energy content factor of fuel type (i), measured in gigajoules per cubic metre that is:
(a) mentioned in column 3 of Part 2 of Schedule 1; or
(b) estimated by analysis under Subdivision 2.3.3.2.
Ci is the density of fuel type (i) expressed in kilograms of fuel per cubic metre as obtained under subsection 2.24(4).